GASTAR EXPLORATION, INC. - FORM 8-K - EX-99.1 - CONSOLIDATED AUDITED FINANCIAL STATEMENTS (DECEMBER 31, 2010)

Attached files

file	filename
8-K - FORM 8-K - GASTAR EXPLORATION, INC.	d8k.htm
EX-23.1 - CONSENT OF BDO USA, LLP - GASTAR EXPLORATION, INC.	dex231.htm
EX-23.2 - CONSENT OF BDO USA, LLP - GASTAR EXPLORATION, INC.	dex232.htm
EX-99.2 - CONSOLIDATED UNAUDITED FINANCIAL STATEMENTS (MARCH 31, 2011) - GASTAR EXPLORATION, INC.	dex992.htm

Exhibit 99.1

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


	Page

Reports of Independent Registered Public Accounting Firm		F-2

Gastar Exploration Ltd. Consolidated Balance Sheets as of December 31, 2010 and 2009		F-4

Gastar Exploration Ltd. Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008		F-5

Gastar Exploration Ltd. Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2010, 2009 and 2008		F-6

Gastar Exploration Ltd. Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008		F-7

Gastar Exploration USA, Inc. Consolidated Balance Sheets as of December 31, 2010 and 2009		F-8

Gastar Exploration USA, Inc. Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008		F-9

Gastar Exploration USA, Inc. Consolidated Statements of Stockholder’s Equity for the Years Ended December 31, 2010, 2009 and 2008		F-10

Gastar Exploration USA, Inc. Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008		F-11

Notes to Consolidated and Gastar Exploration USA, Inc. Financial Statements		F-12

F-1

Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

Gastar Exploration Ltd.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Gastar Exploration Ltd. (the “Company”) and subsidiaries as of December 31, 2010 and 2009 and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gastar Exploration Ltd. at December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 9 to the consolidated financial statements, effective January 1, 2009, the Company changed its method of accounting for certain common stock purchase warrants with the adoption of new guidance on determining whether an instrument is indexed to an entity’s own stock. Also, as discussed in Note 2 to the consolidated financial statements, effective December 31, 2009, the Company changed its reserve estimates and related disclosures as a result of adopting new oil and natural gas reserve estimation and disclosure requirements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Gastar Exploration Ltd.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 10, 2011 expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Dallas, Texas

March 10, 2011

F-2

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholder

Gastar Exploration USA, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Gastar Exploration USA, Inc. (the “Company”) and subsidiaries as of December 31, 2010 and 2009 and the related consolidated statements of operations, stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits include consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gastar Exploration USA, Inc. at December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, effective December 31, 2009, the Company changed its reserve estimates and related disclosures as a result of adopting new oil and natural gas reserve estimation and disclosure requirements.

/s/ BDO USA, LLP

Dallas, Texas

May 26, 2011

F-3

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,
	2010			2009
	(in thousands, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	7,439		$	21,866
Term deposit		—			69,662
Accounts receivable, net of allowance for doubtful accounts of $571 and $609, respectively		4,034			5,336
Receivable from unproved property sale		—			19,412
Commodity derivative contracts		10,229			4,870
Prepaid expenses		1,191			669

Total current assets		22,893			121,815


PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, excluded from amortization		162,230			132,720
Proved properties		345,042			313,100

Total natural gas and oil properties		507,272			445,820
Furniture and equipment		1,175			867

Total property, plant and equipment		508,447			446,687
Accumulated depreciation, depletion and amortization		(293,332	)		(284,026	)

Total property, plant and equipment, net		215,115			162,661

OTHER ASSETS:
Restricted cash		50			50
Commodity derivative contracts		8,482			10,698
Deferred charges, net		508			764
Drilling advances and other assets		304			250

Total other assets		9,344			11,762


TOTAL ASSETS	$	247,352		$	296,238


LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	9,077		$	8,291
Revenue payable		4,331			4,621
Accrued interest		138			130
Accrued drilling and operating costs		1,490			736
Commodity derivative contracts		1,991			3,678
Commodity derivative premium payable		3,451			1,190
Accrued litigation settlement liability		3,164			—
Short-term loan		—			17,000
Accrued taxes payable		—			75,887
Other accrued liabilities		2,024			1,438

Total current liabilities		25,666			112,971


LONG-TERM LIABILITIES:
Commodity derivative contracts		1,521			4,047
Commodity derivative premium payable		4,725			8,176
Accrued litigation settlement liability		800			—
Asset retirement obligation		7,249			5,943
Warrant derivative		—			205

Total long-term liabilities		14,295			18,371


Commitments and contingencies (Note 15)

SHAREHOLDERS’ EQUITY:
Preferred stock, no par value; unlimited shares authorized; no shares issued		—			—
Common stock, no par value; unlimited shares authorized; 64,179,115 and 50,028,592 shares issued and outstanding at December 31, 2010 and 2009, respectively		316,346			263,809
Additional paid-in capital		23,200			20,782
Accumulated deficit		(132,155	)		(119,695	)

Total shareholders’ equity		207,391			164,896


TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	247,352		$	296,238

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

F-4

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Years Ended December 31,
	2010			2009			2008
	(in thousands, except share and per share data)
REVENUES:
Natural gas and oil revenues	$	31,554		$	40,636		$	56,690
Unrealized natural gas hedge gain (loss)		11,214			(7,767	)		6,529

Total revenues		42,768			32,869			63,219

EXPENSES:
Production taxes		370			439			1,324
Lease operating expenses		6,679			6,572			7,567
Transportation, treating and gathering		4,654			1,547			2,002
Depreciation, depletion and amortization		9,306			16,484			24,451
Impairment of natural gas and oil properties		—			68,729			14,217
Accretion of asset retirement obligation		396			379			335
General and administrative expense		14,638			15,649			14,299
Litigation settlement expense		21,744			—			—

Total expenses		57,787			109,799			64,195


LOSS FROM OPERATIONS		(15,019	)		(76,930	)		(976	)

OTHER INCOME (EXPENSE):
Interest expense		(150	)		(3,993	)		(5,853	)
Early extinguishment of debt		—			(15,902	)		—
Investment income and other		1,347			1,267			1,542
Gain on sale of assets		—			211,162			—
Unrealized warrant derivative gain (loss)		205			(205	)		—
Foreign transaction gain		353			3,764			(74	)


INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES		(13,264	)		119,163			(5,361	)

Provision for income tax expense (benefit)		(804	)		70,317			—


NET INCOME (LOSS)	$	(12,460	)	$	48,846		$	(5,361	)


NET INCOME (LOSS) PER SHARE:
Basic	$	(0.25	)	$	1.06		$	(0.13	)

Diluted	$	(0.25	)	$	1.06		$	(0.13	)


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		49,813,617			46,102,662			41,419,714
Diluted		49,813,617			46,210,424			41,419,714

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

F-5

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY


	Common Stock				Additional			Accumulated						Total
	Shares		Amount		Paid-in Capital			Other Comprehensive Income (Loss)			Accumulated Deficit			Shareholders’ Equity
	(in thousands, except share data)
Balance at December 31, 2007		41,639,481	$	249,980	$	14,366		$	(509	)	$	(168,568	)	$	95,269
Issuance of restricted shares, net of forfeitures		287,580		—		—			—			—			—
Issuance of warrants		—		—		5,388			—			—			5,388
Stock based compensation		—		—		3,129			—			—			3,129
Comprehensive loss:
Commodity derivatives reclassified to earnings and other		—		—		—			2,096			—			2,096
Unrealized gain on commodity derivative contracts		—		—		—			1,061			—			1,061
Net loss		—		—		—			—			(5,361	)		(5,361	)

Comprehensive loss		—		—		—			—			—			(2,204	)

Balance at December 31, 2008		41,927,061		249,980		22,883			2,648			(173,929	)		101,582
Cumulative effect of reclassification of warrants		—		—		(5,388	)		—			5,388			—
Issuance of shares - cash, net of offering costs of $771		7,300,000		13,829		—			—			—			13,829
Issuance of restricted shares, net of forfeitures		801,531		—		(260	)		—			—			(260	)
Stock based compensation		—		—		3,547			—			—			3,547
Comprehensive income:
Commodity derivatives reclassified to earnings and other		—		—		—			(2,648	)		—			(2,648	)
Net income		—		—		—			—			48,846			48,846

Comprehensive income		—		—		—			—			—			46,198

Balance at December 31, 2009		50,028,592		263,809		20,782			—			(119,695	)		164,896
Issuance of shares - cash, net of offering costs of $2,663		13,800,000		52,537		—			—			—			52,537
Issuance of restricted shares, net of forfeitures		349,502		—		(347	)		—			—			(347	)
Exercise of stock options, net of forfeitures		1,021		—		—			—			—			—
Stock based compensation		—		—		2,765			—			—			2,765
Comprehensive loss:
Net loss		—		—		—			—			(12,460	)		(12,460	)

Comprehensive loss		—		—		—			—			—			(12,460	)

Balance at December 31, 2010		64,179,115	$	316,346	$	23,200		$	—		$	(132,155	)	$	207,391

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

F-6

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2010			2009			2008
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(12,460	)	$	48,846		$	(5,361	)
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Depreciation, depletion and amortization		9,306			16,484			24,451
Impairment of natural gas and oil properties		—			68,729			14,217
Stock-based compensation		2,765			3,547			3,129
Unrealized natural gas hedge (gain) loss		(11,214	)		7,767			(6,529	)
Realized loss (gain) on derivative contracts		1,437			(3,053	)		—
Amortization of deferred financing costs and debt discount		283			1,964			1,998
Accretion of asset retirement obligation		396			379			335
Loss on early extinguishment of debt		—			7,027			—
Gain on sale of assets		—			(211,162	)		—
Unrealized warrant derivative (gain) loss		(205	)		205			—
Litigation settlement payable		3,150			—			—
Changes in operating assets and liabilities:
Restricted cash for hedging program		—			—			1,000
Accounts receivable		1,565			2,278			(1,946	)
Commodity derivative contracts		1,232			2,893			—
Prepaid expenses		(522	)		151			228
Accrued taxes payable		(1,420	)		75,887			—
Accounts payable and accrued liabilities		(287	)		(8,498	)		8,488

Net cash (used in) provided by operating activities		(5,974	)		13,444			40,010


CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of natural gas and oil properties		(58,512	)		(49,230	)		(130,487	)
Drilling advances		(300	)		(6,044	)		(7,485	)
Acquisition of natural gas and oil properties		(28,887	)		—			—
Proceeds from sale of natural gas and oil properties		49,197			251,267			—
Purchase of furniture and equipment		(308	)		(42	)		(328	)
Purchase of term deposit		(4,855	)		(69,662	)		—
Other		—			—			50

Net cash (used in) provided by investing activities		(43,665	)		126,289			(138,250	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common shares, net of issuance costs		52,537			13,829			—
Proceeds from short-term loan		—			17,000			—
Proceeds from term loan		—			25,000			—
Proceeds from revolving credit facility		—			—			18,875
Repayment of 12³/4% senior secured notes		—			(100,000	)		—
Repayment of term loan		—			(25,000	)		—
Repayment of revolving credit facility		—			(18,875	)		—
Repayment of convertible senior unsecured subordinated debentures		—			(30,000	)		—
Repayment of subordinated unsecured notes		—			(3,250	)		—
Repayment of short-term loan		(17,000	)		—			—
Decrease in restricted cash		—			20			4
Deferred financing charges		(27	)		(2,466	)		(388	)
Other		(298	)		(278	)		48

Net cash provided by (used in) financing activities		35,212			(124,020	)		18,539


NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(14,427	)		15,713			(79,701	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		21,866			6,153			85,854

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	7,439		$	21,866		$	6,153

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

F-7

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,
	2010			2009
	(in thousands, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	7,401		$	21,808
Term deposit		—			69,662
Accounts receivable, net of allowance for doubtful accounts of $571 and $609, respectively		4,034			5,333
Receivable from unproved property sale		—			19,412
Commodity derivative contracts		10,229			4,870
Prepaid expenses		999			447

Total current assets		22,663			121,532


PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, excluded from amortization		162,230			132,720
Proved properties		345,034			313,092

Total natural gas and oil properties		507,264			445,812
Furniture and equipment		1,175			867

Total property, plant and equipment		508,439			446,679
Accumulated depreciation, depletion and amortization		(293,325	)		(284,019	)

Total property, plant and equipment, net		215,114			162,660

OTHER ASSETS:
Restricted cash		25			25
Commodity derivative contracts		8,482			10,698
Deferred charges, net		508			729
Drilling advances and other assets		304			250

Total other assets		9,319			11,702


TOTAL ASSETS	$	247,096		$	295,894


LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES:
Accounts payable	$	9,071		$	8,251
Revenue payable		4,331			4,621
Accrued interest		138			32
Accrued drilling and operating costs		1,490			736
Commodity derivative contracts		1,991			3,678
Commodity derivative premium payable		3,451			1,190
Accrued litigation settlement liability		3,164			—
Accrued taxes payable		—			75,887
Other accrued liabilities		2,017			1,223

Total current liabilities		25,653			95,618


LONG-TERM LIABILITIES:
Commodity derivative contracts		1,521			4,047
Commodity derivative premium payable		4,725			8,176
Accrued litigation settlement liability		800			—
Asset retirement obligation		7,243			5,937
Due to Parent		25,193			22,144

Total long-term liabilities		39,482			40,304


Commitments and contingencies (Note 15)

STOCKHOLDER’S EQUITY:
Preferred stock, $0.01 par value; 10,000,000 shares authorized; no shares issued		—			—
Common stock, no par value; 1,000 shares authorized; 750 shares issued and outstanding at December 31, 2010 and 2009, respectively		240,431			206,894
Accumulated deficit		(58,470	)		(46,922	)

Total stockholder’s equity		181,961			159,972


TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	247,096		$	295,894

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

F-8

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Years Ended December 31,
	2010			2009			2008
	(in thousands)
REVENUES:
Natural gas and oil revenues	$	31,553		$	40,634		$	56,689
Unrealized natural gas hedge gain (loss)		11,214			(7,767	)		6,529

Total revenues		42,767			32,867			63,218

EXPENSES:
Production taxes		370			439			1,324
Lease operating expenses		6,676			6,568			7,567
Transportation, treating and gathering		4,654			1,547			2,002
Depreciation, depletion and amortization		9,306			16,484			24,451
Impairment of natural gas and oil properties		—			68,729			14,217
Accretion of asset retirement obligation		396			379			335
General and administrative expense		13,468			14,368			13,169
Litigation settlement expense		21,744			—			—

Total expenses		56,614			108,514			63,065


INCOME (LOSS) FROM OPERATIONS		(13,847	)		(75,647	)		153

OTHER INCOME (EXPENSE):
Interest expense		(97	)		(731	)		(2,059	)
Early extinguishment of debt		—			(15,902	)		—
Investment income and other		1,238			1,074			1,488
Gain on sale of assets		—			211,162			—
Foreign transaction gain (loss)		354			3,768			(14	)


INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES		(12,352	)		123,724			(432	)

Provision for income tax (benefit) expense		(804	)		70,117			—


NET INCOME (LOSS)	$	(11,548	)	$	53,607		$	(432	)

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

F-9

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY


	Common Stock					Accumulated						Total
	Shares		Amount			Other Comprehensive Income (Loss)			Accumulated Deficit			Shareholder's Equity
	(in thousands, except share data)

Balance at December 31, 2007		750	$	214,894		$	(507	)	$	(100,097	)	$	114,290
Dividend to Parent				(4,000	)		—			—			(4,000	)
Comprehensive loss:
Commodity derivatives reclassified to earnings and other		—		—			2,083			—			2,083
Unrealized gain on commodity derivative contracts		—		—			1,061			—			1,061
Net loss		—		—			—			(432	)		(432	)

Comprehensive loss		—		—			—			—			2,712

Balance at December 31, 2008		750		210,894			2,637			(100,529	)		113,002
Dividend to Parent		—		(4,000	)		—			—			(4,000	)
Comprehensive income:
Commodity derivatives reclassified to earnings and other		—		—			(2,637	)		—			(2,637	)
Net income		—		—			—			53,607			53,607

Comprehensive income		—		—			—			—			50,970

Balance at December 31, 2009		750		206,894			—			(46,922	)		159,972
Dividend to Parent		—		(19,000	)		—			—			(19,000	)
Contribution from Parent		—		52,537			—			—			52,537
Net loss		—		—			—			(11,548	)		(11,548	)

Balance at December 31, 2010		750	$	240,431		$	—		$	(58,470	)	$	181,961

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

F-10

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2010			2009			2008
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(11,548	)	$	53,607		$	(432	)
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Depreciation, depletion and amortization		9,306			16,484			24,451
Impairment of natural gas and oil properties		—			68,729			14,217
Stock-based compensation		2,765			3,547			3,129
Unrealized natural gas hedge (gain) loss		(11,214	)		7,767			(6,529	)
Realized loss (gain) on derivative contracts		1,437			(3,053	)		—
Amortization of deferred financing costs and debt discount		247			1,293			1,460
Accretion of asset retirement obligation		396			379			335
Loss on early extinguishment of debt		—			7,027			—
Gain on sale of assets		—			(211,162	)		—
Litigation settlement payable		3,150			—			—
Changes in operating assets and liabilities:
Accounts receivable		1,562			2,279			(1,954	)
Commodity derivative contracts		1,232			2,893			—
Prepaid expenses		(552	)		128			182
Accrued taxes payable		(1,420	)		75,887			—
Accounts payable and accrued liabilities		53			(8,381	)		8,710

Net cash (used in) provided by operating activities		(4,586	)		17,424			43,569


CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of natural gas and oil properties		(58,512	)		(49,230	)		(130,487	)
Drilling advances		(300	)		(6,044	)		(7,485	)
Acquisition of natural gas and oil properties		(28,887	)		—			—
Proceeds from sale of natural gas and oil properties		49,197			251,267			—
Purchase of furniture and equipment		(308	)		(42	)		(328	)
Purchase of term deposit		(4,855	)		(69,662	)		—
Other		—			—			50

Net cash (used in) provided by investing activities		(43,665	)		126,289			(138,250	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from term loan		—			25,000			—
Proceeds from revolving credit facility		—			—			18,875
Repayment of 12³/4% senior secured notes		—			(100,000	)		—
Repayment of term loan		—			(25,000	)		—
Repayment of revolving credit facility		—			(18,875	)		—
Decrease in restricted cash		—			20			—
Deferred financing charges		(27	)		(2,217	)		(353	)
Distribution from (dividend to) Parent, net		33,822			(6,939	)		(3,508	)
Other		49			(8	)		—

Net cash provided by (used in) financing activities		33,844			(128,019	)		15,014


NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(14,407	)		15,694			(79,667	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		21,808			6,114			85,781

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	7,401		$	21,808		$	6,114

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

F-11

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO 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 prospective deep structures identified through seismic and other analytical techniques as well as unconventional natural gas reserves, such as shale resource plays. Gastar Exploration Ltd. is currently pursuing natural gas exploration in the deep Bossier gas play in the Hilltop area of East Texas and the Marcellus Shale play in the Appalachia area of West Virginia and central and southwestern Pennsylvania. Gastar Exploration Ltd. also conducts coal bed methane (“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

Basis of Presentation

These financial statements are a combined presentation of the 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 consolidated information for the Company presented herein and the consolidated information of Gastar USA.

The consolidated financial statements of the Company and Gastar USA are stated in U.S. dollars unless otherwise noted and have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The preparation of these financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, related disclosure of contingent assets and liabilities, proved natural gas and oil reserves and the related disclosures in the accompanying consolidated financial statements. 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. See Note 19, “Supplemental Oil and Gas Disclosures.”

Reclassifications

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

Subsequent Events

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 consolidated financial statements, as appropriate.

F-12

Principles of Consolidation

The consolidated financial statements of the Company include the accounts of the Parent and the consolidated accounts of all its subsidiaries. The wholly-owned subsidiaries included in these consolidated accounts are Gastar USA, Gastar Exploration Texas, Inc. (“Gastar Texas, Inc.”), Gastar Exploration Texas LP (“Gastar Texas”), Gastar Exploration Texas LLC (“Gastar Texas LLC”), Gastar Exploration New South Wales, Inc. (“Gastar New South Wales”), Gastar Exploration Victoria, Inc. (“Gastar Victoria”) and, prior to 2009, Gastar Power Pty Ltd. (“Gastar Power”). All significant intercompany accounts and transactions have been eliminated in consolidation.

The consolidated financial statements of Gastar USA include the accounts of Gastar USA and the consolidated accounts of all its subsidiaries. The wholly-owned subsidiaries included in these consolidated accounts are Gastar Texas, Inc., Gastar Texas, Gastar Texas LLC, Gastar New South Wales, Gastar Victoria, and, prior to 2009, Gastar Power. All significant intercompany accounts and transactions have been eliminated in consolidation.

Cash and Cash Equivalents

The Company’s cash and cash equivalents, which includes short-term investments such as money market deposits with a maturity of three months or less when purchased, amounted to $7.4 million and $21.9 million as of December 31, 2010 and 2009, respectively. The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant risk of loss.

Term Deposit

Term deposit represents the investment in interest bearing cash term deposits with a major foreign bank earning interest at rates of 4.19% ($53.6 million) and 4.80% ($16.1 million) with a maturity of June 1, 2010. These term deposits were pledged to the Australian Tax Office in connection with the sale of the Australian Assets. Upon maturity on June 1, 2010, the term deposits were used to settle the Australian tax liability resulting from the Australian property sale in 2009. See Note 3, “Property, Plant and Equipment.”

Accounts Receivable

Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is determined based on a review of the Company’s receivables. Receivable accounts are charged off when collection efforts have failed and the account is deemed uncollectible.

A summary of the activity related to the allowance for doubtful accounts is as follows:


	For the Years Ended December 31,
	2010			2009		2008
	(in thousands)

Allowance for doubtful accounts, beginning of year	$	609		$	560	$	4,315
Expense		—			49		—
Reductions		(38	)		—		(3,755	)

Allowance for doubtful accounts, end of year	$	571		$	609	$	560

Deferred Financing Costs and Debt Discount

Deferred financing costs include costs of debt financings undertaken by the Company, including commissions, legal fees and other direct costs of financing. Using the effective interest method, the deferred financing costs are amortized over the term of the related debt instrument to interest expense.

Debt discount is amortized over the term of the related debt utilizing the effective interest method.

F-13

The following table indicates deferred charges and related accumulated amortization as of the dates indicated:


	As of December 31,
	2010			2009
	(in thousands)

Deferred charges	$	1,974		$	1,947
Accumulated amortization		(1,466	)		(1,183	)

Deferred charges, net	$	508		$	764

Natural Gas and Oil Properties

The Company follows the full cost method of accounting for natural gas and oil operations, whereby all costs incurred in the acquisition, exploration and development of natural gas and oil reserves are initially capitalized into cost centers on a country-by-country basis and are amortized as reserves are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. With the sale of the Company’s Australian Assets (as defined under Note 3, “Property, Plant and Equipment – Sale of Petroleum Exploration Licenses 238, 433 and 434 and Repayment of Debt”) in 2009, the United States is the Company’s only remaining cost center. Capitalized costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities.

Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves, as determined by independent petroleum engineers.

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether an impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property is added to costs subject to depletion calculations.

In applying the full cost method of accounting, the Company performs a quarterly ceiling test on the cost center properties whereby the net cost of natural gas and oil properties, net of related deferred income taxes (“net cost”), is limited to the sum of the estimated future net revenues from the Company’s proved reserves using prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month price for natural gas and oil prices held constant, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“ceiling”). If the net cost exceeds the ceiling, an impairment loss is recognized for the amount by which the net cost exceeds the ceiling and is shown as a reduction in natural gas and oil properties and as additional depletion expense. Proceeds from a sale of natural gas and oil properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion or amortization.

The Company’s estimate of proved reserves is based on the quantities of natural gas and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell & Associates, Inc. (“NSAI”) prepares a reserve and economic evaluation of all the Company’s properties on a well-by-well basis utilizing information provided by the Company and information available from state agencies that collect information reported to it by the operators of Company’s properties. As discussed below, the estimate of the Company’s proved reserves as of December 31, 2010 and 2009 have been prepared and presented in accordance with current rules and accounting standards promulgated by the Securities and Exchange Commission (the “SEC”). These rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on a 12-month unweighted arithmetic average of the first-day-of-the-month price. The previous rules required that reserve estimates be calculated using year-end pricing.

Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates and the projected cash flows derived from these reserve

F-14

estimates in accordance with SEC guidelines. NSAI adheres to the same guidelines when preparing the reserve report. The accuracy of the Company’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.

The Company’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas, oil and natural gas liquids eventually recovered.

Capitalized Interest

The Company capitalizes interest on assets not being amortized related to specific projects such as its drilling in progress and unproven natural gas and oil property expenditures. The methodology for capitalizing interest on general funds begins with a determination of the borrowings applicable to the qualifying assets. The basis of this approach is the assumption that the portion of the interest costs that are capitalized on expenditures during an asset’s acquisition period could have been avoided if the expenditures had not been made. This methodology takes the view that if funds are not required for construction then they would have been used to pay off debt. The primary debt instrument included in the rate calculation of capitalized interest incurred for the year-ended December 31, 2010 was Gastar USA’s Revolving Credit Facility (as defined under Note 5, “Long-Term Debt”). Currently, the Company only capitalizes interest on the Revolving Credit Facility. The interest to be capitalized for any period is derived by multiplying the average rate of interest times the average qualifying assets during the period, not to exceed the total interest on the qualifying debt instruments. To qualify for interest capitalization, the Company must continue to make progress on the development of the assets. Capitalized interest costs were approximately $633,000, $10.8 million and $12.2 million for 2010, 2009 and 2008, respectively.

Furniture and Equipment

Furniture and equipment are recorded at historical cost and are depreciated on a straight-line basis over their estimated useful lives, which range from three to seven years.

Fair Value of Financial Instruments

The fair value of financial instruments is determined at discrete points in time based on relevant market information. Such estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, term deposit, accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. Derivative instruments are also recorded on the balance sheet at fair value.

Derivative Instruments and Hedging Activity

The Company uses derivative instruments in the form of natural gas costless collars, index swaps, basis swaps and put options to manage price risks resulting from fluctuations in commodity prices of natural gas and oil associated with future natural gas production. Derivative instruments are recorded on the balance sheet at fair market value and changes in the fair market value of derivatives are recorded each period in current earnings. Fair value is assessed, measured and estimated by obtaining forward commodity pricing, credit adjusted risk-free interest rates and, as necessary, estimated volatility factors. The fair values the Company reports in its consolidated financial statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond the Company’s control. Gains and losses on derivatives are included in revenue in the period in which they occur. The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 9, “Derivative Instruments and Hedging Activity.”

Prior to October 1, 2008, the Company designated and accounted for its derivative instruments as cash flow hedges. Accordingly, changes in the fair values of the Company’s cash flow hedges were deferred and recorded in accumulated other comprehensive income, as appropriate, until recognized as natural gas and oil revenues in the Company’s consolidated statements of operations as the hedged production was delivered and affected earnings. For all derivative instruments previously designated as cash flow hedges, the Company was required to assess the effectiveness of the hedging relationships at inception and on a quarterly basis.

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Effective October 1, 2008, the Company discontinued hedge accounting on all existing derivative contracts and elected not to designate any additional derivative contracts as cash flow hedges. As a result, any subsequent changes in the fair values of discontinued cash flow hedging instruments or new derivative contracts for future production are recognized in unrealized natural gas hedge gain (loss) within the Company’s consolidated statements of operations. Any gains or losses previously deferred under cash flow hedge accounting remained in accumulated other comprehensive income until the previously hedged production affected earnings or was no longer probable of occurring. All amounts previously recorded in other comprehensive income in 2008 were recorded in natural gas and oil revenues during 2009 as the hedged production was delivered. For 2009 and 2010, realized gains or losses from derivative contracts are included in natural gas and oil revenues in the Company’s consolidated statement of operations.

Revenue Recognition

The Company uses the sales method of accounting for the sale of its natural gas and oil and records revenues from the sale of natural gas and oil when delivery to the customer has occurred and title has transferred. This recording of revenues occurs when natural gas or oil has been delivered to a pipeline or a tank lifting has occurred. Under the sales method, revenues are recorded based on the Company’s net revenue interest, as delivered. When actual natural gas sales volumes exceed our delivered share of sales volumes, an over-produced imbalance occurs. To the extent an over-produced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. The Company had no material gas imbalances at December 31, 2010 and 2009.

The Company records its share of revenues based on production volumes and contracted sales prices. The sales price for natural gas and oil are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents once received by the Company. In addition, natural gas and crude oil volumes sold are not significantly different from the Company’s share of production.

The Company calculates and pays royalties on natural gas, crude oil and natural gas liquids in accordance with the particular contractual provisions of the lease. Royalty liabilities are recorded in the period in which the natural gas and oil are produced and are included in revenue payable on the Company’s consolidated balance sheet.

Asset Retirement Obligation

Asset retirement costs and liabilities associated with future site restoration and abandonment of tangible long-lived assets are initially measured at fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash expenditures for site restoration and abandonment. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost, through depreciation, depletion and amortization, are recognized in the results of operations.

Foreign Currency Exchange

The consolidated financial statements of the Company are presented in U.S. dollars. The functional currency for the parent and all consolidated subsidiaries is U.S. dollars. Transactions in currencies other than the functional currency are recorded using the appropriate exchange rate at the time of the transaction.

The majority of the Company’s operations are conducted in U.S. dollars. Prior to July 2009, the Company conducted natural gas and oil property development in Australia. The Australian Assets were sold in July 2009, prior to reaching commercial operations. As a result of the sale of the Australian Assets, the Company no longer has long lived assets outside of the U.S. Limited operations are conducted by the parent in Canada.

F-16

The Australian and Canadian records are maintained in the local currency and re-measured to the functional currency as follows: monetary assets and liabilities are converted using the balance sheet period-end date exchange rate, while the non-monetary assets and liabilities are converted using the historical exchange rate. Expenses and income items are converted using the weighted average exchange rates for the reporting period. Foreign transaction gains and losses are reported on the consolidated statement of operations.

Deferred Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as income in the period that includes the enactment date. The Company has established a valuation reserve to offset its net deferred tax asset since, on a more likely than not basis, such benefits are not considered recoverable at this time.

Earnings or Loss per Share

Basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding plus the incremental effect of the assumed issuance of common shares for all potentially dilutive securities. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common shares are exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options, unvested restricted shares and warrants.

Stock-Based Compensation

The Company reports compensation expense for stock options and restricted common shares granted to officers, directors and employees using the fair value method. Stock-based compensation costs are recorded over the requisite service period, which approximates the vesting period. Stock-based compensation expense is recognized using the “graded-vesting method”, which recognizes compensation costs over the requisite service period for each separately vesting tranche of an award as though the award were, in substance, multiple awards.

The Company records stock-based compensation costs for stock options granted based on the grant-date fair value as calculated using the Black-Scholes-Merton option-pricing model. The Black-Scholes-Merton model requires various highly judgmental assumptions including volatility, forfeiture rates and expected option life. If any of the assumptions used in the Black-Scholes-Merton model change significantly, stock-based compensation expense for future grants may differ materially from that recorded in the current period. Stock-based compensation cost for restricted shares granted is estimated at the grant date based on the prior day’s closing stock price.

Joint Venture Operations

The majority of the Company’s natural gas and oil exploration activities are conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities.

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development and production of natural gas and oil. Historically, the Company’s operational activities have been conducted in the U.S. and Australia, with only the U.S. having revenue generating operating results. All Australian operations were sold on July 13, 2009. As a result, the Company’s current operational activities and the Company’s consolidated revenues are generated from markets exclusively in the U.S. and substantially all of the Company’s assets are held within the U.S.

F-17

Treasury Stock

The Parent’s common shares are without par value. Treasury stock purchases are recorded at cost as a reduction to common stock. Common shares are canceled upon repurchase.

Restricted Cash

The Company is required to maintain cash balances that are restricted by provisions of certain banking and other agreements. Restricted cash is invested in short-term instruments at market rates; therefore, the carrying value approximates fair value. Such cash is reported as restricted cash and is excluded from cash and cash equivalents in the consolidated balance sheets.

Recent Accounting Developments

The following recently issued accounting pronouncements have been adopted or may impact us in future periods:

Business Combinations. In December 2010, the Financial Accounting Standards Board (“FASB”)’s Emerging Issues Task Force (“EITF”) 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 the Company’s operating results, financial position or cash flows.

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

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

F-18

Fair Value Measurements. In January 2010, the FASB issued authoritative guidance related to improving disclosures about fair value measurements. This guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements shall be presented separately. These disclosures are required for interim and annual reporting periods effective January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January 1, 2011. This guidance was adopted on January 1, 2010 and did not impact the Company’s operating results, financial position or cash flows but did require additional disclosures regarding the fair value of financial instruments. See Note 7, “Fair Value Measurements.”

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

Modernization of Natural Gas and Oil Reporting. In January 2009, the SEC issued revisions to the natural gas and oil reporting disclosures, “Modernization of Oil and Gas Reporting, Final Rule” (the “Final Rule”). In addition to changing the definition and disclosure requirements for natural gas and oil reserves, the Final Rule changed the requirements for determining quantities of natural gas and oil reserves. The Final Rule requires the use of the 12-month unweighted arithmetic average of the first-day-of-the-month prices for natural gas and oil, rather than the end-of-period price used prior to adoption of the Final Rule, in estimating reserves. The Final Rule also changed certain accounting requirements under the full cost method of accounting for natural gas and oil activities. The amendments are designed to modernize the requirements for the determination of natural gas and oil reserves, aligning them with current practices and updating them for changes in technology. The Final Rule was effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. In addition, in January 2010, the FASB issued an accounting standards update relating to standards for extractive oil and gas activities. The accounting standards update amends existing standards to align the proved reserves calculation and disclosure requirements under U.S. GAAP with the requirements in the SEC rules. The Company adopted the new standards effective December 31, 2009. The new standards were applied prospectively as a change in estimate. The application of this guidance will continue to result in future amounts recorded for depreciation, depletion and amortization and ceiling limitations being different from what would have been recorded had the Final Rule not been mandated. In April 2010, the FASB issued a further accounting standards update regarding extractive oil and gas industries to incorporate in accounting standards the revisions to Rule 4-10 of the SEC’s Regulation S-X. The amendment primarily consists of the addition and deletion of definitions of terms related to fossil fuel exploration and production arising from technology changes over the past several decades. The accounting guidance in Rule 4-10 did not change.

F-19

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 states of Texas, Pennsylvania, West Virginia, Wyoming and Montana in the U.S. The Company’s Australian properties were sold in July 2009. The Company’s total property, plant and equipment consists of the following:


	December 31,
	2010			2009
	(in thousands)

Natural gas and oil properties, full cost method of accounting:
Unproved properties	$	162,230		$	132,720
Proved properties		345,042			313,100

Total natural gas and oil properties		507,272			445,820
Furniture and equipment		1,175			867

Total property and equipment		508,447			446,687
Impairment of proved natural gas and oil properties		(187,152	)		(187,152	)
Accumulated depreciation, depletion and amortization		(106,180	)		(96,874	)

Total accumulated depreciation, depletion and amortization		(293,332	)		(284,026	)

Total property and equipment, net	$	215,115		$	162,661

As of December 31, 2010, unproved properties not being amortized consisted of drilling in progress costs of $17.6 million, acreage acquisition costs of $126.4 million and capitalized interest of $18.2 million. At December 31, 2009, unproved properties not being amortized consisted of drilling in progress costs of $3.8 million, acreage acquisition costs of $111.0 million, and capitalized interest of $17.9 million. For the years ended December 31, 2010 and 2009, management’s evaluation of unproved properties did not result in an impairment of unproved properties.

For the year ended December 31, 2010, management’s ceiling test evaluation did not result in an impairment of proved properties. The December 31, 2010 ceiling test evaluation utilized a weighted average natural gas price of $3.53 per Mcf. For the years ended December 31, 2009 and 2008, the results of management’s ceiling test evaluation resulted in an impairment of proved properties of $68.7 million and $14.2 million, respectively. The 2009 proved property impairment was recorded at March 31, 2009 based on a weighted average natural gas price of $2.64 per Mcf at March 31, 2009. The December 31, 2008 proved property impairment was calculated based on a a weighted average natural gas price of $4.56 per Mcf.

Atinum Joint Venture

In September 2010, Gastar USA entered into a purchase and sale agreement with Atinum, an affiliate of Atinum Partners Co., Ltd, a Korean investment firm. Pursuant to the agreement, at the closing of the transactions on November 1, 2010, 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, in a transaction valued at $70.0 million. Atinum paid Gastar USA approximately $30.0 million in cash at the closing and will pay an additional $40.0 million over time for a drilling carry. Upon completion of the funding of the drilling carry, 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 December 31, 2010, approximately $38.5 million of drilling carry obligations remained outstanding.

Gastar USA and Atinum are pursuing an initial three-year development program that calls for the partners to drill one horizontal Marcellus Shale well during the remainder of 2010, a minimum of 12 horizontal wells in 2011 and 24 horizontal wells in each of 2012 and 2013. An initial Area of Mutual Interest (“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 the initial AMI, Gastar USA

F-20

will act as operator and is obligated to offer any future AMI lease acquisitions to Atinum on a 50/50 basis, and Atinum will pay 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 will have the right to participate in any future 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.

Total cash consideration received by Gastar USA was approximately $30.0 million and reduced proved property and unproved property costs by approximately $5.0 million and $25.0 million, respectively.

Marcellus Shale Leasehold Acquisition

In December 2010, Gastar USA completed a $28.9 million Marcellus Shale acquisition. The acquisition consisted of approximately 62,000 net acres of 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 wells producing approximately 500 Mcf per day (gross) of natural gas. This acreage is not included in the Atinum Joint Venture and the counties will not be part of the related AMI.

Total cash consideration paid by Gastar USA was $28.9 million. Gastar USA allocated $19.9 million to unproved properties and $9.0 million to proved properties based on the fair value of the assets acquired at the acquisition date.

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

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

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

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

The Company used the proceeds from the sale of the Australian Assets to (i) repay the $13.0 million outstanding on Gastar USA’s secured original revolving credit facility, (ii) repay in full Gastar USA’s $25.0 million term loan, (iii) repurchase all of Gastar USA’s outstanding $100.0 million 12³/4% senior secured notes due December 31, 2012 at a price of 106.375% of par, plus accrued and unpaid interest, (iv) repay, at par, an initial $10.3 million of Parent’s convertible subordinated debentures and (v) repay the remaining $300,000 of the Parent’s subordinated unsecured notes payable (described in Note 5, “Long-Term Debt”).

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Sale of East Texas Gas Gathering System

On November 16, 2009, Gastar USA completed the sale of all of its interest in the Hilltop gas gathering system (the “Hilltop Gathering System”), located in Leon and Robertson Counties, Texas. Gastar USA entered into a purchase and sale agreement with Hilltop Resort GS, LLC (“Hilltop Resort”), dated as of November 16, 2009 (the “Hilltop Sale Agreement”) pursuant to which Gastar USA conveyed its 70% interest in the Hilltop Gathering System to Hilltop Resort for approximately $19.1 million, net of transaction costs and expenses. Gastar USA also entered into purchase and sale agreements dated November 16, 2009 with two existing working interest owners in the Hilltop area of East Texas, whereby Gastar USA conveyed the remaining 30% of its interest in the Hilltop Gathering System for an aggregate $2.7 million, net of working interest owner costs owed to Gastar USA. Total consideration received by Gastar USA was approximately $21.8 million, net of transaction costs and expenses, and reduced proved property costs.

At the time of the sale, the Hilltop Gathering System was comprised of 20 miles of natural gas pipeline connected to 19 Company-operated wells, which produce from the middle and lower Bossier and Knowles formations in East Texas.

On November 16, 2009, concurrent with Gastar USA’s sale of its Hilltop Gathering System, Gastar Texas entered into a gas gathering agreement (“Hilltop Gathering Agreement”) effective November 1, 2009, with Hilltop Resort for an initial term of 15 years. The Hilltop Gathering Agreement covers delivery of Gastar USA’s gross production of natural gas in the Hilltop area of East Texas to certain delivery points provided under the gas sales contract, as well as additional delivery points that, from time to time, may be added. Gastar USA is also obligated to connect new wells that it drills within the area covered by the Hilltop Gathering Agreement to the Hilltop Gathering System. The Hilltop Gathering Agreement provides for a minimum quarterly gathering gross production volume of 50.0 MMcf per day (35.0 MMcf per day net to Gastar USA) times the number of days in the quarter for five years from the effective date of November 1, 2009. If quarterly production is less than the minimum quarterly requirement, the gathering fee is payable on such deficit. If excess quarterly production exists, such excess is carried forward to be used to offset any future deficit quarters. The gathering fee on the initial gross 25 Bcf of production is $0.325 per Mcf, reducing in steps to $0.225 per Mcf when cumulative gross production reaches 300 Bcf. For the year ended December 31, 2010, Gastar USA paid $1.3 million to Hilltop Resort as a result of not meeting minimum quarterly requirements. There is no assurance that Gastar USA will meet its minimum quarterly requirements in the future.

4. Short-Term Loan

On November 20, 2009, Parent, entered into a $17.0 million secured short-term loan agreement with the lender parties and administrative agent thereto (the “Short-Term Loan”). Concurrent with the execution of the Short-Term Loan, Parent drew $17.0 million and used the proceeds, together with cash on hand, to repay all $19.7 million of its outstanding 9.75% convertible senior unsecured subordinated debentures due November 20, 2009 (the “Convertible Subordinated Debentures”).

The Short-Term Loan bore interest at the floating prime rate of the lender. The prime rate at December 31, 2009 was 5.0% per annum. Amounts outstanding under the Short-Term Loan were repayable prior to maturity, together with all accrued and unpaid interest relating to the amount prepaid, without prepayment penalty. The Short-Term Loan contained various covenants, including restrictions on liens, restrictions on incurring other indebtedness without the lenders’ consent, restrictions on dividends and other restricted payments and restrictions on entering into certain transactions.

Amounts outstanding under the Short-Term Loan were secured by a second priority lien on all of the issued and outstanding shares of Gastar USA, pursuant to the Second Lien Security Agreement (Pledge) dated November 20, 2009 (“Second Lien”), by and between the Company and the administrative agent for the lenders under the Short-Term Loan. Additionally, amounts outstanding under the Short-Term Loan were secured by a security interest in all funds of the Company on deposit with the administrative agent and each lender that was a party to the Short-Term Loan.

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In order to provide for Parent’s borrowings under the Short-Term Loan and related repayments and the granting of the Second Lien, on November 20, 2009, Gastar USA, together with Parent and certain of its subsidiaries as the guarantors (“Subsidiary Guarantors”), and the lenders and administrative agent party thereto, entered into the Consent and First Amendment to Amended and Restated Credit Agreement (the “First Amendment”) amending the Company’s Revolving Credit Agreement. See Note 5, “Long-Term Debt, Revolving Credit Facility.”

The Short-Term Loan was repaid in full on January 8, 2010.

5. Long-Term Debt

Revolving Credit Facility

On November 29, 2007, concurrent with the closing of the sale of 12³/4% Senior Secured Notes (described under “12³/4% Senior Secured Notes”), Gastar USA entered into a secured revolving credit facility (the “Original Revolving Credit Facility”) that provided for a first priority lien borrowing base. The Original Revolving Credit Facility was guaranteed by Parent and all of its current domestic subsidiaries and all of its future domestic subsidiaries that may be formed during the term of the Original Revolving Credit Facility. The related guarantees under the Original Revolving Credit Facility were secured by a first priority lien on all domestic natural gas and oil properties currently owned by or later acquired by Gastar USA, excluding de minimus value properties as determined by the lender.

On July 13, 2009, Gastar USA used a portion of the net proceeds from the sale of the Australian Assets to repay the $13.0 million then outstanding under the Original Revolving Credit Facility.

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

In order to provide for Parent’s borrowings under the Short-Term Loan and related repayments and the granting of the Second Lien on November 20, 2009, Gastar USA, together with Parent and Subsidiary Guarantors and the lender parties and administrative agent thereto, entered into the First Amendment amending the Revolving Credit Facility. In addition to permitting the incurrence of debt under the Short-Term Loan, the First Amendment also amended the Revolving Credit Facility, by, among other things, reducing the borrowing base from $47.5 million to $30.5 million until the Short-Term Loan was repaid in full, at which time the borrowing base would be automatically increased to $47.5 million until the next scheduled borrowing base redetermination. The borrowing base was increased to $47.5 million from $30.5 million subsequent to the repayment of the Short-Term Loan in January 2010.

The Revolving Credit Facility is guaranteed by Parent and all its current domestic subsidiaries and all future domestic subsidiaries formed during the term of the Revolving Credit Facility. Borrowings and related guarantees under the Revolving Credit Facility are secured by a first priority lien on all domestic natural gas and oil properties 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.

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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 quarter 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 of Control” (as defined in the Revolving Credit Facility) of Parent.

Should there occur a Change of 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, 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”). The Second Amendment amended the Revolving Credit Facility, by, among other things, allowing Gastar USA (i) to hedge up to 80% of the proved developed producing (“PDP”) reserves reflected in its reserve report using hedging other than floors and protective spreads, (ii) relatedly, to present to the administrative agent a report showing any PDP additions resulting from new wells or the conversion of proved developed non-producing reserves to PDP reserves since the last reserve report in order to hedge the revised PDP reserves, and (iii) removing limitations on hedging using floors and protective spreads. Additionally, the Second Amendment reduced the borrowing base under the Revolving Credit Facility to $40.0 million from $47.5 million, primarily in connection with delays in returning the Belin #1 well, located in the Hilltop area of East Texas, to production following re-completion attempts. Subsequent to the redetermination of the borrowing base and entry into the Second Amendment, the Belin #1 well was returned to production from all zones. On October 1, 2010, the borrowing base was increased to $47.5 million from the previous borrowing base of $40.0 million.

As of December 31, 2010, Gastar USA had nothing outstanding under the Revolving Credit Facility and the availability under the borrowing base was $47.5 million. Borrowing base redeterminations are scheduled semi-annually in May and November of each calendar year, with the next redetermination scheduled for May 2011. Gastar USA and the lenders may request one additional unscheduled redetermination annually.

At June 30, 2010, Gastar USA was not in compliance with the 80% hedge limitation for 2011 under the Revolving Credit Facility; Gastar USA was in compliance with all other financial covenants under the Revolving Credit Facility at such time. Gastar USA was granted a waiver in regards to the hedge limitation through March 31, 2011 and in conjunction with such waiver, at December 31, 2010, Gastar USA was in compliance with all financial covenants under the Revolving Credit Facility.

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Credit support for the Company’s open derivatives at December 31, 2010 is provided through inter-creditor agreements or open accounts.

$25.0 Million Term Loan

On February 17, 2009, Gastar USA drew $25.0 million under a $25.0 million term loan (the “$25.0 Million Term Loan”) to fund current and future capital commitments and operating costs. The $25.0 Million Term Loan bore interest at a fixed rate of 20% per annum and was to mature on February 15, 2012. The annual effective interest rate, after amortization of the fees paid to establish the $25.0 Million Term Loan was 21.9%. The $25.0 Million Term Loan contained various customary covenants, including restrictions on liens, restrictions on incurring other indebtedness without the lender’s consent, restrictions on dividends and other restricted payments, and maintenance of various financial ratios consistent to the Original Revolving Credit Facility. Amounts outstanding under the $25.0 Million Term Loan could be repaid prior to maturity, with a prepayment premium of 10% if repaid prior to December 31, 2009, and a prepayment premium of 5% if repaid between January 1, 2010 and December 31, 2010. Upon a Change of Control (as defined in the $25.0 Million Term Loan), all amounts outstanding under the $25.0 Million Term Loan were to be immediately due and payable.

Amounts outstanding under the $25.0 Million Term Loan were secured by a first priority lien on Gastar USA’s and certain of its subsidiaries’ primary natural gas and oil assets and certain other properties. The $25.0 Million Term Loan was fully and unconditionally guaranteed jointly and severally by Gastar USA, Parent and all of Parent’s existing and future material domestic subsidiaries. The $25.0 Million Term Loan and other existing and future indebtedness incurred under Gastar USA’s Original Revolving Credit Facility were senior to the liens securing the 12³/4% Senior Secured Notes.

On July 13, 2009, Gastar USA used approximately $27.5 million of the proceeds from the Australian Assets sale, described above, to repay in full, and thereby terminate, the $25.0 Million Term Loan.

12³/4% Senior Secured Notes

On November 29, 2007, Gastar USA sold $100.0 million aggregate principal amount of 12³/4% senior secured notes (the “12³/4% Senior Secured Notes”) at an issue price of 99.50% pursuant to an indenture, dated as of November 29, 2007 (the “Base Indenture”), by and among Parent, Gastar USA, Wells Fargo Bank, National Association, as trustee and Collateral Agent (the “Trustee”) and certain subsidiaries of Parent. The 12³/4% Senior Secured Notes were fully and unconditionally guaranteed (the “Guarantees”) jointly and severally by Gastar USA, Parent, and all of Parent’s existing and future material domestic subsidiaries. The 12 ³/4% Senior Secured Notes and the Guarantees were secured by a second lien on Gastar USA’s principal domestic natural gas and oil properties and other assets that also secured the Original Revolving Credit Facility, subject to certain exceptions. The 12³/4% Senior Secured Notes were to mature on December 1, 2012. On February 16, 2009, the parties to the Base Indenture entered into a supplemental indenture with the Trustee to amend and modify the Indenture (the “Supplemental Indenture” and together with the Base Indenture, the “Indenture”) to enable Gastar USA to enter into the $25.0 Million Term Loan.

On July 13, 2009, Gastar USA initiated an offer (the “Asset Sale Offer”) to purchase any and all of its outstanding 12 ³/4% Senior Secured Notes from the holders upon the terms and subject to the conditions set forth in the asset sale offer statement, dated July 13, 2009 (the “Asset Sale Offer Statement”). The Asset Sale Offer Statement was made in accordance with the terms of the Indenture.

The purpose of the Asset Sale Offer was to comply with the provisions of the Supplemental Indenture and the Base Indenture, whereby if Gastar USA had major asset sale excess proceeds (as defined therein) following the receipt of net proceeds from a sale of assets, Gastar USA was required to offer to purchase the maximum principal amount of 12³/4% Senior Secured Notes that could be purchased with such major asset sale excess proceeds.

On August 6, 2009, the note-holders tendered to Gastar USA the outstanding $100.0 million principal amount of the 12³/4% Senior Secured Notes at 106.375% of par, plus accrued and unpaid interest. On August 7, 2009, Gastar USA used a portion of the net proceeds from the sale of the Australian Assets to retire in full the 12³/4% Senior Secured Notes and to discharge all of its obligations under the Indenture by directly tendering payment of $108.7 million, including accrued interest, to the note-holders and ultimate cancellation of the 12 ³/4% Senior Secured Notes by the Trustee.

F-25

Convertible Subordinated Debentures

In November 2004, Parent issued $30.0 million of Convertible Subordinated Debentures. The Convertible Subordinated Debentures had a term of five years, were due November 20, 2009 and bore interest at 9.75% per annum, payable quarterly. As of September 30, 2009, a total of $10.3 million of Convertible Subordinated Debentures had been tendered, at par, to Parent for early retirement. Concurrent with the execution of the Short-Term Loan on November 20, 2009, Parent drew $17.0 million and used the proceeds, together with cash on hand, to repay all $19.7 million of outstanding Convertible Subordinated Debentures.

Subordinated Unsecured Notes Payable

The Parent’s $3.25 million 10.0% subordinated unsecured notes payable (the “Subordinated Unsecured Notes Payable”) matured from April to September 2009. As of December 31, 2009, Parent had repaid all outstanding amounts under the Subordinated Unsecured Notes Payable.

6. Asset Retirement Obligation

A summary of the activity related to the asset retirement obligation is as follows:


	For the Years Ended December 31,
	2010			2009
	(in thousands)

Asset retirement obligation, beginning of year	$	5,943		$	5,095
Liabilities incurred during period		1,023			652
Accretion expense		396			379
Revision in previous estimates and other		(113	)		(183	)

Asset retirement obligation, end of year	$	7,249		$	5,943

7. Fair Value Measurements

The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized non-financial assets and liabilities, such as asset retirement obligations and other property and equipment, at fair value on a non-recurring basis. For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements to assess the inputs used to develop these measurements. As none of the Company’s non-financial assets and liabilities were impaired during the period-ended December 31, 2010, and no other fair value measurements are required to be recognized on a non-recurring basis, no additional disclosures are provided at December 31, 2010.

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

•

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.

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•

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

•

Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. These inputs may be used with internally developed methodologies or third party broker quotes that result in management’s best estimate of fair value. The Company’s valuation models consider various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments. Level 3 instruments are natural gas costless collars, index, basis and fixed price swaps, put and call options and warrants. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

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

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 December 31, 2010 and 2009:


	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
Liabilities:
Commodity derivative contracts		—		—		(3,512	)		(3,512	)

Total	$	7,489	$	—	$	15,199		$	22,688


	Fair value as of December 31, 2009
	Level 1		Level 2		Level 3			Total
	(in thousands)

Assets:
Cash and cash equivalents	$	21,866	$	—	$	—		$	21,866
Term deposit		69,662		—		—			69,662
Restricted cash		50		—		—			50
Commodity derivative contracts		—		—		15,568			15,568
Liabilities:
Commodity derivative contracts		—		—		(7,725	)		(7,725	)
Warrant derivative		—		—		(205	)		(205	)

Total	$	91,578	$	—	$	7,638		$	99,216

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The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2010 and 2009. 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 December 31, 2010 and 2009.


	For the Years Ended December 31,
	2010			2009
	(in thousands)
Balance at beginning of period	$	7,638		$	8,708
Total gains (losses) (realized or unrealized):
included in earnings (1)		15,509			4,076
included in other comprehensive income		—			—
Purchases		—			—
Issuances		—			—
Settlements		(7,948	)		(5,146	)
Transfers in and (out) of Level 3		—			—

Balance at end of period	$	15,199		$	7,638


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 December 31, 2010 and 2009	$	11,419		$	(7,972	)

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

At December 31, 2010, the estimated fair value of cash and cash equivalents, accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature.

The fair value guidance, as amended, establishes that every derivative instrument is to be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 9, “Derivative Instruments and Hedging Activity.”

8. Equity Compensation Plans

Share-Based Compensation Plan

At the annual meeting of shareholders held June 4, 2009 (the “Annual Meeting”), Parent’s shareholders approved amendments to Parent’s 2006 Long-Term Stock Incentive Plan (the “2006 Plan”) that, effective as of April 1, 2009, merged Parent’s Stock Option Plan (the “2002 Stock Option Plan”) with and into the 2006 Plan so that all outstanding equity awards and all future equity awards to be made to employees, officers and directors of the Company would be under one plan – the 2006 Plan. The merging of the 2002 Stock Option Plan with and into the 2006 Plan resulted in the cessation of the existence of the 2002 Stock Option Plan and the transfer of all common shares previously reserved and available for issuance under the 2002 Stock Option Plan, including any common shares subject to outstanding stock option awards previously granted under the 2002 Stock Option Plan prior to the effective date of the amendments, to the common shares reserved under the 2006 Plan.

Additionally, the amendments to the 2006 Plan (a) provide that the Remuneration Committee of the Parent, at its discretion, may provide, in an award agreement, that an individual who is granted an award under the 2006 Plan (a “participant”) may elect to have common shares withheld from or netted against the total number of common shares otherwise issuable to such participant pursuant to his award in order to pay the exercise or purchase price of such award and/or to satisfy all employer tax withholding obligations with respect to the participant’s award under the 2006 Plan, (b) clarify that common shares issuable under the 2006 Plan and forfeited back to the 2006 Plan will be deemed not to have been issued under the 2006 Plan and will again be available for the grant of an award under the 2006 Plan, (c) provide that common shares withheld from or netted against an award granted under the 2006

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Plan for payment of (1) the exercise or purchase price of an award and (2) all applicable employer tax withholding obligations associated with an award will be deemed not to have been issued under the 2006 Plan and will again be available for the grant of an award under the 2006 Plan, (d) provide that the maximum number of common shares that may be subject to stock options, bonus stock awards and stock appreciation rights granted to any one individual during any calendar year may not exceed 200,000 common shares (subject to adjustment pursuant to Section 11(a) of the 2006 Plan) and (e) provide that the definition of “performance criteria” in the 2006 Plan include a criteria relating to the growth of proved natural gas and oil reserves of the Company.

The Parent’s 2006 Plan authorizes Parent’s Board of Directors (the “Parent Board”) to issue stock options, stock appreciation rights, bonus stock awards and any other type of award, which are consistent with the 2006 Plan’s purposes to directors, officers and employees of the Company covering a maximum of 6.0 million common shares. The contractual lives and vesting periods for grants are determined by the Parent Board at the time a grant is awarded. Recent stock option grants have an expiration of ten years. The vesting schedule for stock option grants has varied from two years to four years but generally has been over a four-year period vesting at 25% per year beginning on the first anniversary date of the grant. Stock options granted pursuant to the 2006 Plan have exercise prices determined by the Parent Board, but an exercise price cannot be less than the market price on the date immediately prior to the date of grant as reported by any stock exchange on which Parent’s common shares are listed. The vesting period for recent restricted common stock grants has been over four years with 25% vesting on the first, second, third, and fourth anniversaries, respectively, from the date of grant.

On August 3, 2009, Parent’s common shares began trading on a post 1-for-5 reverse split (the “1-for-5 Reverse Split”) basis. All common shares and per share information has been adjusted to reflect the 1-for-5 Reverse Split. See Note 10, “Capital Stock.”

At December 31, 2010, 1,543,675 common shares of Parent were available for future stock-based compensation grants under the 2006 Plan. All common shares issued upon the exercise of stock option grants or vesting of restricted share grants are authorized, issued by Parent and are fully paid and non-assessable.

Determining Fair Value of Stock Options

In determining the fair value of stock option grants, the Company utilized the following assumptions:

Valuation and Amortization Method. The Company estimates the fair value of stock option awards using the Black-Scholes-Merton valuation model. The fair value of all awards is expensed using the “graded-vesting method”.

Expected Life. The expected life of stock options granted represents the period of time that stock options are expected, on average, to be outstanding. The Company determined the expected life to be 6.25 years, based on historical information, for all stock options issued with four-year vesting periods and ten-year grant expirations.

Expected Volatility. Using the Black-Scholes-Merton valuation model, the Company estimates the volatility of Parent’s common shares at the beginning of the quarter in which the stock option is granted. The volatility is based on weighted average historical movements of Parent’s common share price on the NYSE Amex over a period that approximates the expected life.

Risk-Free Interest Rate. The Company utilizes a risk-free interest rate equal to the rate of U.S. Treasury zero-coupon issues as of the date of grant with a term equivalent to the stock option’s expected life.

Expected Dividend Yield. The Parent has not paid any cash dividends on its common shares and does not anticipate paying any cash dividends in the foreseeable future. Consequently, a dividend yield of zero is utilized in the Black-Scholes-Merton valuation model.

Expected Forfeitures. Forfeitures of unvested stock option and restricted common shares are calculated at the beginning of the year as a percentage of all stock option and restricted common share grants. For 2010, 2009 and 2008, the Company used forfeiture rates in determining compensation expense of 9.8%, 6.5% and 6.0%, respectively.

F-29

The fair value of each stock option grant is estimated on the date of grant using the Black-Scholes-Merton valuation pricing model. The table below summarizes the number of stock options granted and the fair value assumptions for the stock options granted for the period indicated:


	For the Years Ended December 31,
	2010			2009			2008
Stock options granted during the period		80,000			266,300			—
Expected life (in years)		6.25			6.25			—
Expected volatility		68.10	%		59.3% - 60.2	%		—
Risk-free interest rate		2.33% - 2.94	%		1.97% - 2.81	%		—
Expected dividend rate		0.00	%		0.00	%		—

The weighted average grant date fair value of stock options granted and the intrinsic value of stock options exercised are shown below for the periods indicated:


	For the Years Ended December 31,
	2010		2009		2008
	(in thousands, except per share data)

Weighted average grant date fair value per stock option granted	$	2.66	$	1.52	$	—
Intrinsic value of stock options exercised (1)	$	7	$	—	$	—
Grant date fair value of stock options vested	$	739	$	1,334	$	3,233

(1)	Intrinsic value of stock options is calculated using the difference between the common share price on the date of exercise and the exercise price times the number of stock options exercised.

Stock Option Activity

The following tables summarize certain information related to outstanding stock options under Parent’s 2006 Plan as of and for the year ended December 31, 2010:


	Shares			Weighted Average Exercise Price per Share		Weighted Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2009		1,292,300		$	12.13
Granted		80,000			4.17
Exercised		(3,000	)		2.60
Canceled/Expired		(117,200	)		14.36
Forfeited		(145,000	)		10.54

Outstanding at December 31, 2010		1,107,100		$	10.85


Options vested and exercisable at December 31, 2010		817,825		$	13.33		5.73	$	96


	Shares			Weighted Average Fair Value per Share		Weighted Average Exercise Price per Share		Weighted Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (in thousands)
Outstanding non-vested options at December 31, 2009		422,383		$	7.19
Granted		80,000			2.66
Vested		(142,275	)		5.20
Forfeited		(70,833	)		4.73

Outstanding non-vested options at December 31, 2010		289,275		$	2.21	$	3.85		8.36	$	314

F-30

Unrecognized expense as of December 31, 2010 for all outstanding options is $253,000 and will be recognized over a weighted average period of 2.36 years.

The total intrinsic value of options exercised during the year ended December 31, 2010 was $7,000. There were no options exercised for the years ended December 31, 2009 and 2008. Intrinsic value of stock options is calculated using the difference between the common share price on the date of exercise and the exercise price times the number of stock options exercised.

Restricted Share Activity

The following table summarizes information related to restricted shares of the Parent at December 31, 2010:


	Shares			Weighted Average Fair Value per Share		Weighted Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (in thousands)
Non-vested restricted shares outstanding at December 31, 2009		1,034,324		$	6.03
Granted		440,550			4.84
Vested		(312,785	)		6.78
Forfeited		—			—

Outstanding non-vested restricted shares at December 31, 2010		1,162,089		$	5.38		8.47	$	4,997

The following table summarizes the weighted average grant date fair value of restricted shares granted and the total fair value of shares vested for the periods indicated:


	For the Years Ended December 31,
	2010		2009		2008
	(in thousands, except per share data)

Weighted average grant date fair value per restricted share	$	4.84	$	6.03	$	10.10
Total fair value of restricted shares vested	$	2,121	$	1,480	$	—

Unrecognized compensation expense as of December 31, 2010 for all outstanding restricted share awards is $2.6 million and will be recognized over a weighted average period of 2.36 years.

Stock-Based Compensation Expense

For the years ended December 31, 2010, 2009 and 2008, the Company recorded stock-based compensation expense for stock options and restricted shares granted using the fair-value method of $2.8 million, $3.5 million and $3.1 million, respectively. All stock-based compensation costs were expensed and not tax affected, as the Company currently records no U.S. income tax expense.

As of December 31, 2010, the Company had approximately $2.9 million of total unrecognized compensation cost related to unvested stock options and restricted shares, which is expected to be amortized over the following periods:


	Amount
	(in thousands)

2011	$	1,783
2012		790
2013		289
2014		38

Total	$	2,900

F-31

9. Derivative Instruments and Hedging Activity

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

Effective October 1, 2008, the Company elected to discontinue hedge accounting on all existing derivative contracts and elected not to designate any derivative contracts as cash flow hedges. Any hedge effectiveness related to the Company’s previous cash flow hedging relationships were to remain in other comprehensive income until the underlying forecasted transactions affected earnings. As a result, for the years ended December 31, 2009 and 2008, the Company reported gains of $2.6 million and $22,000, respectively, which were reclassified into earnings as a result of previously discontinued cash flow hedges. As of December 31, 2009, all other comprehensive income had been reclassified to earnings. All derivative contracts are carried at their fair value on the balance sheet and all unrealized gains and losses are recorded in the statement of operations in unrealized natural gas hedge gain (loss), while realized gains and losses related to contract settlements are recognized in natural gas and oil revenues. For the years ended December 31, 2010 and 2008, the Company reported unrealized gains of $11.2 million and $6.5 million, respectively. For the year ended December 31, 2009, the Company reported an unrealized loss of $7.8 million.

As of December 31, 2010, the following derivative transactions were outstanding with the associated notational volumes and weighted average underlying hedge prices:


Settlement Period	Derivative Instrument	Average Daily Volume		Total of Notional Volume		Base Fixed Price			Floor (Long)		Short Put		Ceiling (Short)
		(in MMBtu’s)

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

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

(1)	East Houston-Katy – Houston Ship Channel

(2)	Inside FERC Colorado Interstate Gas, Rocky Mountains

As of December 31, 2010, all of the Company’s economic derivative hedge positions were with a multinational energy company or large financial institutions, which are not known to the Company to be in default on their derivative positions. Credit support for the Company’s open derivatives at December 31, 2010 is provided under the Revolving Credit Facility through inter-creditor agreements or open credit accounts of up to $5.0 million. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contains credit-risk related contingent features.

F-32

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:


	December 31, 2010		December 31, 2009
	(in thousands)
Current commodity derivative premium payable	$	3,451	$	1,190
Long-term commodity derivative premium payable		4,725		8,176

Total unamortized put premium liabilities	$	8,176	$	9,366

The following table provides information regarding the amortization of the deferred put premium liabilities by year as of December 31, 2010:


	Amortization
	(in thousands)
January - December 2011	$	3,451
January - December 2012		4,725

Total unamortized put premium liabilities	$	8,176

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 shares was zero as of December 31, 2010, and Parent recognized $205,000 in unrealized gains in other income for the change in fair value of these warrants for the year ended December 31, 2010.

The following warrants to purchase common shares were outstanding as of December 31, 2010:

Warrants

Outstanding

Fair Value
(in thousands)

Weighted
Price per
Share Range

Average
Remaining
Life in
Years

Average
Exercise
Price

2,000,000

—

)

0.9

)

(1)

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

F-33

Additional Disclosures about Derivative Instruments and Hedging Activities

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


	Fair Values of Derivative Instruments Derivative Assets (Liabilities)
		Fair Value
	Balance Sheet Location	December 31, 2010			December 31, 2009
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Current assets	$	10,229		$	4,870
Commodity derivative contracts	Other assets		8,482			10,698
Commodity derivative contracts	Current liabilities		(1,991	)		(3,678	)
Commodity derivative contracts	Long-term liabilities		(1,521	)		(4,047	)
Warrant derivative	Long-term liabilities		—			(205	)


Total derivatives not designated as hedging instruments		$	15,199		$	7,638


	Amount of Gain (Loss) Recognized in Income on Derivatives
		Amount of Gain (Loss) Recognized in Income on Derivatives For the Year Ended
	Location of Gain (Loss) Recognized in Income on Derivatives	December 31, 2010			December 31, 2009
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Unrealized natural gas hedge gain (loss)	$	11,214		$	(7,767	)
Warrant derivative	Unrealized warrant derivative gain (loss)		205			(205	)

Total		$	11,419		$	(7,972	)

10. Capital Stock

Parent Common Shares

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

Effective July 6, 2009, Parent elected to voluntarily de-list its shares from trading on the Toronto Stock Exchange (“TSX”). The Parent decided to delist from the TSX because trading on two exchanges had become unduly costly and burdensome without providing any significant additional liquidity for Parent’s shareholders.

Parent Preferred Shares

On June 30, 2009, Parent filed an amendment to its articles of incorporation to be effective as of June 30, 2009 with the Registrar of Corporations of Alberta, Canada for the purpose of creating and adding an unlimited number of preferred shares to the authorized capital of the Parent. The Parent’s shareholder’s approved the amendment by

F-34

special resolution at the 2007 Annual General and Special Meeting of Shareholders held on June 1, 2007. Pursuant to the amendment, the number of preferred shares which may be issued from time to time and the privileges, restrictions and conditions of such preferred shares when issued will be determined by the Parent Board. At December 31, 2010, there were no preferred shares issued or outstanding.

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 December 31, 2010 and 2009, 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.

Gastar USA Preferred Stock

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

The stockholder’s 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.

Other Share Issuances

On May 22, 2009, Parent sold 7,300,000 of its common shares in an underwritten public offering to investors in the U.S. pursuant to Parent’s registration statement on Form S-3, which was declared effective by the SEC on April 27, 2007, at a price of $2.00 per share, or $14.6 million before offering costs. On December 13, 2010, Parent sold 13,800,000 of its common shares in an underwritten public offering to investors in the U.S. pursuant to Parent’s registration statement on Form S-3, which was declared effective by the SEC on April 27, 2007, at a price of $4.00 per share, or $55.2 million before offering costs.

F-35

The following table provides information regarding the issuance and forfeitures of common shares pursuant to Parent’s 2006 Plan for the periods indicated:


	For the Year Ended December 31,
	2010		2009
Other share issuances:
Restricted common shares granted		440,550		956,035
Restricted common shares vested		312,785		372,702
Stock options exercised		3,000		—
Common shares forfeited (1)		93,027		98,715
Common shares canceled		—		55,789

(1)

Represents common shares forfeited in connection with the payment of estimated withholding taxes on restricted common shares that vested during the period and/or common shares forfeited in connection with the payment of estimated withholding taxes and to settle the exercise price in cashless option exercises.

Shares Reserved

The following table summarizes the components of Parent’s common shares reserved at December 31, 2010:


Common shares reserved for the:
Exercise of stock options			1,107,100
Exercise of warrants			2,000,000

Total common shares reserved			3,107,100

11. Interest and Debt Extinguishment Expense

The following table summarizes the components of the Company’s interest and debt extinguishment expense for the periods indicated:


	For the Year Ended December 31,
	2010			2009			2008
	(in thousands)
Interest expense:
Cash and accrued	$	500		$	12,831		$	16,080
Amortization of deferred financing costs and debt discount		283			1,964			1,998
Capitalized interest		(633	)		(10,802	)		(12,225	)

Total interest expense	$	150		$	3,993		$	5,853

Early extinguishment of debt:
Call premium	$	—		$	8,875		$	—
Unamortized deferred financing costs and debt discount		—			7,027			—

Total debt extinguishment expense	$	—		$	15,902		$	—

F-36

The following table summarizes the components of Gastar USA’s interest and debt extinguishment expense for the periods indicated:


	For the Year Ended December 31,
	2010			2009			2008
	(in thousands)
Interest expense:
Cash and accrued	$	483		$	10,240		$	12,825
Amortization of deferred financing costs and debt discount		247			1,293			1,459
Capitalized interest		(633	)		(10,802	)		(12,225	)

Total interest expense	$	97		$	731		$	2,059

Early extinguishment of debt:
Call premium	$	—		$	8,875		$	—
Unamortized deferred financing costs and debt discount		—			7,027			—

Total debt extinguishment expense	$	—		$	15,902		$	—

12. Related Party Transactions

Chesapeake Energy Corporation

Chesapeake Energy Corporation (“Chesapeake”) acquired 6,781,767 of Parent’s common shares during 2005 to 2007 in private placement transactions. Chesapeake has the right to have an observer present at meetings of the Parent Board.

As of December 31, 2010, Chesapeake owned 6,781,767 of Parent’s common shares, or 10.6%, of Parent’s outstanding common shares.

13. Income Taxes

The following table summarizes the components of the Company’s income (loss) before income taxes for the periods indicated:


	For the Year Ended December 31,
	2010			2009			2008
	(in thousands)
United States	$	(13,916	)	$	(90,174	)	$	(300	)
Foreign		652			209,337			(5,061	)

Total income (loss) before income taxes	$	(13,264	)	$	119,163		$	(5,361	)

The Company’s income tax expense consists of the following:


	For the Year Ended December 31,
	2010			2009		2008
	(in thousands)
Current:
Federal	$	—		$	200	$	—
State		(12	)		175		—
Foreign		(792	)		69,942		—

Provision for income taxes	$	(804	)	$	70,317	$	—

F-37

The following table provides a reconciliation of the Company’s effective tax rate from the U. S. 35% statutory rate for the periods indicated:


	For the Year Ended December 31,
	2010			2009			2008
	(in thousands)
Expected income tax provision (benefit) at statutory rate	$	(4,642	)	$	41,707		$	(1,876	)
State tax, tax effected		(8	)		114			46
Non-deductible stock-based compensation expense		(4,311	)		271			1,095
Deferred tax effect of Canadian tax rate changes and other		(1,632	)		1,849			3,416
Deferred tax effect of Australian tax rate changes and other		—			722			—
Non-deductible portion of U.S. net operating loss due to dual loss limitation		—			2,035			—
U.S. tax on deemed dividend distribution to Parent		—			200			—
Foreign tax credit adjustment		(1,366	)		—			—
Australian tax rate differences and adjustment		(1,337	)		—			—
Other		(95	)		(169	)		148
Other changes in valuation allowance		12,587			23,588			(2,829	)

Actual income tax provision	$	(804	)	$	70,317		$	—

The components of the Company’s U.S. deferred taxes are as follows:


	As of December 31,
	2010			2009
	(in thousands)
Deferred tax asset (liability):
Capital assets	$	(222	)	$	7,058
Net operating loss carry forwards		16,115			—
Foreign tax credit carry forwards		50,734			49,360
Valuation allowance		(66,627	)		(56,418	)

Net deferred tax asset	$	—		$	—

The Company utilized its U.S. net operating loss carry forwards in 2009 due to the U.S. gain recognition on the sale of the Australian Assets. The Company generated $43.9 million of net operating loss for the year ending December 31, 2010 which, if not utilized, will expire in 2030. For U.S. federal income tax purposes, as of December 31, 2010, the Company has foreign tax credit carry forwards of $50.7 million, which if not utilized, will expire in 2019. The utilization of the net operating loss carry forward and the foreign tax credit carry forward are dependent on the Company generating future taxable income and U.S. tax liability, as well as other factors.

The Parent has the following approximate undeducted Canadian tax pools:


	As of December 31,
	2010		2009
	(in thousands)

Canadian and foreign exploration and development expense	$	1,955	$	1,766
Undeducted share and senior secure note issuance costs	$	2,786	$	1,645
Undeducted non-capital and capital loss carry forwards	$	68,333	$	60,540

For Canadian income tax purposes, Parent has net operating loss carry forwards, which if not utilized, began to expire in 2010 through 2030.

F-38

The components of Parent’s Canadian deferred tax assets are as follows:


	As of December 31,
	2010			2009
	(in thousands)

Deferred tax asset:
Capital assets	$	489		$	442
Share and senior secured note issuance costs		704			369
Tax loss carry forwards		17,022			15,026
Valuation allowance		(18,215	)		(15,837	)

Net deferred tax asset	$	—		$	—

In July 2009, the Company disposed of all of its Australian Assets at a gain. As a result of this transaction, the Company utilized all of its Australian net operating loss carry forwards.

Current authoritative guidance requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For a tax position meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2010, the Company did not have any unrecognized tax benefits that, if recognized, would affect the effective tax rate.

It is expected that the amount of unrecognized tax benefits may change in the next 12 months; however, the Company does not expect the change to have a significant impact on its financial condition or results of operations.

The Company is subject to examination of income tax filings in the U. S., various state jurisdictions and the foreign jurisdictions of Canada and Australia for the tax periods 2000 and forward due to the Company’s continued loss position in such jurisdictions.

Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of general and administrative expense in the consolidated statement of operations. The Company has not recorded any interest or penalties associated with unrecognized tax benefits.

14. Earnings or Loss 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.

F-39


	For the Year Ended December 31,
	2010			2009		2008
	(in thousands, except per share and share data)
Net income (loss)	$	(12,460	)	$	48,846	$	(5,361	)

Weighted average common shares outstanding - basic		49,813,617			46,102,662		41,419,714
Incremental shares from outstanding stock options		—			2,783		—
Incremental shares from unvested restricted shares		—			104,979		—

Weighted average common shares outstanding - diluted		49,813,617			46,210,424		41,419,714
Income (loss) per common share:
Basic	$	(0.25	)	$	1.06	$	(0.13	)
Diluted	$	(0.25	)	$	1.06	$	(0.13	)
Common shares excluded from denominator as anti-dilutive:
Stock options		949,314			1,650,875		1,929,750
Unvested restricted shares		100,078			436,034		506,780
Warrants		2,000,000			2,000,000		2,046,504
Convertible subordinated debentures		—			—		1,369,863

Total		3,049,392			4,086,909		5,852,897

15. Commitments and Contingencies

Contractual Obligations

Gastar USA leases its office facilities and certain office equipment under non-cancelable operating lease agreements. For the years ended December 31, 2010, 2009 and 2008, office lease expense totaled approximately $211,000, $267,000 and $240,000, respectively.

As of December 31, 2010, Gastar USA’s aggregate future minimum annual rental commitments under the non-cancelable leases for the next five years are as follows:


2011	$	4,634
2012		4,244
2013		4,005
2014		3,415
2015		449
Thereafter		302

	$	17,049

Litigation

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

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Court requested briefing on the merits. On January 9, 2009, the Texas Supreme Court denied the Petition for Review. On January 26, 2009, the Company and Chesapeake jointly filed a motion for rehearing in the Texas Supreme Court on its denial of the Petition for Review. On April 24, 2009, the Texas Supreme Court denied the Petition for Review.

Pursuant to a provision in the November 4, 2005 Purchase and Sale and Exploration Development Agreement with Chesapeake, Chesapeake acknowledged the existence of the Navasota lawsuit and claims and further agreed that if Navasota were to prevail on its claims, that Chesapeake would convey the affected interests it purchased from the Company to Navasota upon receipt of the purchase price and/or other consideration paid by Navasota. Therefore, the Company believes that Navasota’s exercise of its rights of specific performance should impact only Chesapeake’s assigned leasehold interests. However, in December 2008, Chesapeake stated to the Company that if the Texas Supreme Court were not to reverse the decision of the Tenth Court of Appeals, Chesapeake would seek rescission of the 2005 transaction and restitution of consideration paid, indicating that Chesapeake might assert such rescission and restitution as to the November 4, 2005 Purchase and Sale and Exploration Development Agreement; a November 4, 2005 Exploration and Development Agreement; and a November 4, 2005 Common Share Purchase Agreement. In its December 2008 communication, Chesapeake did not identify particular sums as to which it might seek restitution, but amounts paid to the Company in connection with the 2005 transaction could be asserted to include the $76.0 million paid by Chesapeake for the purchase of 5.5 million common shares as part of the transaction in 2005 and/or other amounts. Chesapeake has amended its Answer to include cross-claims and counterclaims, including a claim for rescission.

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

The case has been set for trial on July 26, 2011. The Company intends to vigorously defend all claims asserted in the suit.

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

In re ClassicStar Mare Lease Litigation; In the United States District Court for the Eastern District of Kentucky (Master File No. 5:07-cv-353-JMH). The Company and seven of its subsidiaries were named among several defendants in seven matters (known as Raifman, West Hills Farms, AA-J Breeding, LLC, Goyak, Lyon, Stanwyck Glen Farms, LLC, and Premiere Thoroughbreds, LLC) that had been consolidated for pretrial purposes as part of a multi-district litigation proceeding along with other matters to which the Company was not a party. Effective November 1, 2010, the Company and its subsidiaries entered into a Final Settlement Agreement and Comprehensive General Release (“Settlement”) with the plaintiffs in these seven matters. The Settlement was subject to approval by the United States Bankruptcy Court for the Eastern District of Kentucky overseeing the bankruptcy of ClassicStar LLC, which court approved the settlement by an order dated November 24, 2010. The District Court overseeing the seven litigation matters entered a final order dismissing the plaintiffs’ causes of action with prejudice on December 17, 2010. Pursuant to the Settlement of the seven In re ClassicStar Mare Lease Litigation matters, the Company agreed to pay to the plaintiffs an aggregate of $21.2 million in cash in exchange for a release of all claims by the plaintiffs in the seven matters. The agreed amount included an initial $18.0 million payment that was paid late in the fourth quarter of 2010. The Company is obligated to pay the remaining $3.2 million as a non-interest bearing payment obligation consisting of sixteen monthly payments, the first of which was $150,000 and was paid in January 2011 and the next fifteen of which shall be $200,000 each.

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Midway Land & Development Inc. v. EnCana Oil & Gas (USA), Inc. v. Navasota Resources, LTD, LLP, Alta Mesa Resources LP f/k/a Navasota Resources, Inc., and Navasota Resources LTD., LLP and Gastar Exploration Texas LP and Gastar Exploration, LTD.; In the District Court of Robertson County, Texas, 82ND Judicial District (Judge Stem), (Cause No. 08-12-18,265-CV). Gastar Exploration Texas LP and Gastar Exploration, Ltd. were served as third-party defendants by EnCana Oil & Gas (USA), Inc. on September 8, 2009. The Company understands that the underlying action between Midway Land & Development Inc. and EnCana Oil & Gas (USA), Inc. has been pending since 2008. In the underlying action, Midway seeks to recover from the EnCana defendants a 2.5% working interest on certain wells located on lands within an area of mutual interest incorporated in a Joint Operating Agreement dated July 7, 2000 (“JOA”), between First Source Texas, Inc., as operator, and Navasota Resources, Inc. and Kentex Energy, LLC (Midway’s predecessor in interest). Under the Area of Mutual Interest (“AMI”) agreement, it is alleged that each of the parties has the right to acquire an interest in any lease or a mineral interest acquired by any of the other parties on land situated within the AMI (for consideration set forth in the JOA). The Gastar defendants, among others, own or claim interests in lands that Midway contends are within the AMI. The EnCana defendants seek declaratory relief from the Court declaring that the AMI provision in the JOA is unenforceable because it does not include a legally sufficient description of the lands within the AMI. Further, the EnCana defendants seek to have a stipulation dated September 9, 2003 related to the AMI also declared unenforceable under the Statute of Frauds. It is alleged that the stipulations provides that Kentex (Midway’s predecessor in interest) shall be vested with an undivided five percent after payout working interest in each oil and gas well located on the leases listed on Exhibit A to the Stipulation. The Company has answered the lawsuit and discovery is proceeding. Recently, the Company reached an agreement with the EnCana defendants which will result in the dismissal or non-suit of the Company from the lawsuit.

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 Gastar Texas oil and gas leases covering approximately 4,273.7 gross acres (the “Leases”). In this suit Gastar Texas contends that certain oil and gas leases claimed by the defendants have expired according to their terms and that the defendants’ failure to release those leases constitutes a trespass upon and cloud on the Leases. The defendants have responded with a General Denial and produced a portion of the documents Gastar Texas sought in its Request for Production of Documents. They have also served their own requests for admissions and production of documents, to which Gastar Texas has responded. After repeated demands, the defendants have promised to comply and produce certain documents they obtained from third parties through depositions on written questions. 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 No. 1H well located in Leon County. The parties attended mediation but no settlement was reached. Depositions of the defendants are scheduled for March 2011. A trial date has not been set for this case. Gastar Texas believes it has gathered evidence to diminish the defendant’s interest ownership claims and will continue to vigorously pursue this claim.

The Company has been expensing legal defense costs on these proceedings as they are incurred. With respect to the Navasota Resources, Tillotson and Midway Land & Development 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.

For the year ended December 31, 2010, the Company recorded $21.7 million in litigation settlement expense in the consolidated statement of operations, the majority of which related to the ClassicStar Mare Lease Litigation settlements and short-term and long-term accrued litigation settlement liabilities of $3.2 million and $800,000, respectively, on the consolidated balance sheet at December 31, 2010.

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Commitments

In March 2008, Gastar USA entered into formal agreements with ETC Texas Pipeline, Ltd. (“ETC”) for the gathering, treating, purchase and transportation of Gastar USA’s natural gas production from the Hilltop area of East Texas (the “ETC Contract”). The ETC Contract was effective September 1, 2007 and has a term of 10 years. ETC currently provides Gastar USA 50.0 MMcf per day of treating capacity and 150.0 MMcf per day of transportation capacity of production from Gastar USA’s wells, located in Leon and Robertson Counties, Texas.

On November 16, 2009, concurrent with Gastar USA’s sale of its Hilltop Gathering System, Gastar Texas, a wholly-owned subsidiary entered into a gas gathering agreement (“Hilltop Gathering Agreement”) effective November 1, 2009, with Hilltop Resort for an initial term of 15 years. The Hilltop Gathering Agreement covers delivery of Gastar USA’s gross production of natural gas in the Hilltop area of East Texas to certain delivery points provided under the ETC Contract, as well as additional delivery points that, from time to time, may be added. Gastar USA is also obligated to connect new wells that it drills within the area covered by the Hilltop Gathering Agreement to the Hilltop Gathering System. The Hilltop Gathering Agreement provides for a minimum quarterly gathering gross production volume of 50.0 MMcf per day (35.0 MMcf per day net to Gastar USA) times the number of days in the quarter for five years from the effective date of November 1, 2009. If quarterly production is less than the minimum quarterly requirement, the gathering fee is payable on such deficit. If excess quarterly production exists, such excess is carried forward to be used to offset any future deficit quarters. The gathering fee on the initial gross 25 Bcf of production is $0.325 per Mcf, reducing in steps to $0.225 per Mcf when cumulative gross production reaches 300 Bcf. For the year ended December 31, 2010, Gastar USA paid $1.3 million to Hilltop Resort as a result of not meeting minimum quarterly requirements. There is no assurance that Gastar USA will meet its minimum quarterly requirements in the future.

Restoration, Removal and Environmental Liabilities

The Company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to contractual agreements and management decisions, result in the accrual of estimated future removal and site restoration costs. These costs are initially measured at a fair value and are recognized in the consolidated financial statements as the present value of expected future cash flows. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement obligation cost are recognized in the results of operations. Costs attributable to these commitments and contingencies are expected to be incurred over an extended period of time and are to be funded mainly from the Company’s cash provided by operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, it could be material for any quarter or year. At December 31, 2010, the Company had total liabilities of $7.2 million related to asset retirement obligations recorded as long-term liabilities. Due to the nature of these obligations, the Company cannot determine precisely when the payments will be made to settle these obligations. See Note 6, “Asset Retirement Obligation.”

Indemnifications

Indemnifications in the ordinary course of business have been provided pursuant to provisions of purchase and sale contracts, service agreements, joint venture agreements, operating agreements and leasing agreements. In these agreements, the Company may indemnify counterparties if certain events occur. These indemnification provisions vary on an agreement by agreement basis. In some cases, there are no pre-determined amounts or limits included in the indemnification provisions and the occurrence of contingent events that will trigger payment, if any, is difficult to predict.

Employment Agreements

The Company entered into employment agreements with its Chief Executive Officer and its Chief Financial Officer, effective February 24, 2005 (as amended July 25, 2008 and February 3, 2011) and May 17, 2005 (as amended July 25, 2008), respectively. The agreements set forth, among other things, annual compensation, and adjustments thereto, bonus payments, fringe benefits, termination and severance provisions. The agreements renew annually; however, they may be terminated at any time with or without cause.

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The Company also has entered into agreements with these executives, who are acting at the Company’s request to be officers of the Company, to indemnify them to the fullest extent permitted by law against any and all damages, liabilities, costs, charges or expenses suffered by or incurred by the individuals as a result of their service. The nature of the indemnification agreements prevents the Company from making a reasonable estimate of the maximum potential amount it could be required to pay to the beneficiary of such indemnification agreements.

16. Concentration of Risk and Significant Customers

Approximately 89%, 90% and 77% of the Company’s natural gas and oil revenues for the years ended December 31, 2010, 2009 and 2008, respectively, were derived from production from producing wells in the Hilltop area of East Texas.

For the years ended 2010, 2009 and 2008, ETC accounted for 86%, 85% and 79%, respectively, of natural gas and oil revenues, excluding realized hedge impact. For the years ended 2010, 2009 and 2008, Enserco Energy, Inc. (“Enserco”) accounted for 9%, 13% and 19%, respectively, of natural gas and oil revenues, excluding realized hedge impact.

ETC treats, transports and purchases substantially all of the Company’s East Texas production, and Enserco purchases the Company’s Powder River Basin natural gas production. There are limited natural gas purchase and transportation alternatives currently available in the Hilltop area of East Texas. If ETC were to cease purchasing and transporting the Company’s natural gas and the Company was unable to obtain timely access to existing or future facilities on acceptable terms, or in the event of any significant change affecting these facilities, including delays in the commencement of operations of any new pipelines or the unavailability of the new pipelines or other facilities due to market conditions, mechanical reasons or otherwise, the Company’s ability to conduct normal operations would be restricted. However, the Company believes that the loss of ETC or Enserco would not have a long-term material adverse impact on the Company’s financial position or results of operations, as there are other purchasers operating in the areas.

17. Statement of Cash Flows – Supplemental Information

The following is a summary of the Company’s supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated financial statements:


	For the Year Ended December 31,
	2010		2009			2008
	(in thousands)
Cash paid for interest	$	497	$	14,202		$	16,109
Cash paid for taxes		616		—			—
Cash paid for debt extinguishment		—		8,875			—

Non-cash transactions:
Term deposit surrendered for accrued taxes	$	70,446	$	—		$	—
Capital expenditures excluded from accounts payable and accrued costs		2,725		(5,125	)		(4,905	)
Asset retirement obligation included in natural gas and oil properties		910		516			443
Drilling advances application		246		10,247			5,384
GeoStar settlement		—		—			2,476

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The following is a summary of Gastar USA’s supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated financial statements:


	For the Year Ended December 31,
	2010			2009			2008
	(in thousands)
Cash paid for interest	$	386		$	11,308		$	12,853
Cash paid for taxes		414			—			—
Cash paid for debt extinguishment		—			8,875			—

Non-cash transactions:
Term deposit surrendered for accrued taxes	$	70,446		$	—		$	—
Capital expenditures excluded from accounts payable and accrued costs		2,725			(5,125	)		(4,905	)
Asset retirement obligation included in natural gas and oil properties		910			516			443
Drilling advances application		246			10,247			5,384
GeoStar settlement		—			—			2,476
Due to Parent - transfer to equity, net		(30,773	)		7,546			12,518

18. Quarterly Consolidated Financial Data – Unaudited

The following tables summarize the Company’s results of operations by quarter for the years ended December 31, 2010 and 2009:


	2010
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
	(in thousands, except share and per share data)

Revenues	$	16,136	$	5,765		$	14,144		$	6,723
Income (loss) from operations (1)		7,363		(3,040	)		(16,420	)		(2,922	)
Income (loss) before income taxes		8,544		(2,441	)		(16,423	)		(2,944	)
Net income (loss)		9,393		(2,498	)		(16,411	)		(2,944	)
Income (loss) per share:
Basic	$	0.19	$	(0.05	)	$	(0.33	)	$	(0.06	)
Diluted	$	0.19	$	(0.05	)	$	(0.33	)	$	(0.06	)
Weighted average number of shares:
Basic		48,997,016		49,042,874			49,148,207			52,066,371
Diluted		49,486,656		49,042,874			49,148,207			52,066,371

(1)	Loss from operations for the three months ended September 30, 2010 and December 31, 2010 include litigation settlement expense of $21.2 million and $594,000, respectively.

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	2009
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(in thousands, except share and per share data)

Revenues	$	13,265		$	7,536		$	4,263		$	7,805
Loss from operations (1)		(69,035	)		(1,266	)		(5,944	)		(685	)
Income (loss) before income taxes (2)		(70,187	)		(2,393	)		174,268			17,475
Net income (loss) (3)		(70,187	)		(2,393	)		108,492			12,934
Income (loss) per share:
Basic	$	(1.69	)	$	(0.05	)	$	2.21		$	0.26
Diluted	$	(1.69	)	$	(0.05	)	$	2.21		$	0.26
Weighted average number of shares:
Basic		41,452,423			44,854,954			48,990,509			48,994,268
Diluted		41,452,423			44,854,954			49,107,492			49,277,432

(1)	Loss from operations for the three months ended March 31, 2009 includes an impairment to natural gas and oil properties of $68.7 million.

(2)	Income before income taxes includes a gain on sale of unproved properties of $193.4 million and $17.8 million for the three months ended September 30, 2009 and December 31, 2009, respectively.

(3)	Net income includes an after tax gain on sale of unproved properties of $127.6 million and $13.6 million for the three months ended September 30, 2009 and December 31, 2009, respectively.

The following tables summarize Gastar USA’s results of operations by quarter for the years ended December 31, 2010 and 2009:


	2010
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
	(in thousands, except share and per share data)

Revenues	$	16,136	$	5,765		$	14,144		$	6,722
Income (loss) from operations (1)		7,880		(2,753	)		(16,223	)		(2,751	)
Income (loss) before income taxes		8,965		(2,209	)		(16,235	)		(2,873	)
Net income (loss)		9,814		(2,266	)		(16,223	)		(2,873	)

(1)	Loss from operations for the three months ended September 30, 2010 and December 31, 2010 include litigation settlement expense of $21.2 million and $594,000, respectively.


	2009
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(in thousands, except share and per share data)

Revenues	$	13,265		$	7,535		$	4,262		$	7,805
Loss from operations (1)		(68,764	)		(980	)		(5,675	)		(228	)
Income (loss) before income taxes (2)		(68,998	)		(1,273	)		175,726			18,269
Net income (loss) (3)		(68,998	)		(1,273	)		109,950			13,928

(1)	Loss from operations for the three months ended March 31, 2009 includes an impairment to natural gas and oil properties of $68.7 million.

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(2)	Income before income taxes includes a gain on sale of unproved properties of $193.4 million and $17.8 million for the three months ended September 30, 2009 and December 31, 2009, respectively.

(3)	Net income includes an after tax gain on sale of unproved properties of $127.6 million and $13.6 million for the three months ended September 30, 2009 and December 31, 2009, respectively.

19. Supplemental Oil and Gas Disclosures – Unaudited

Capitalized Costs Relating Oil and Producing Activities

The following table presents the Company’s aggregate capitalized costs relating to natural gas and oil producing activities for the periods indicated:


	For the Year Ended December 31,
	2010			2009			2008
	(in thousands)

Proved properties:
United States	$	345,042		$	313,100		$	308,499
Australia		—			—			604

Total proved properties		345,042			313,100			309,103
Unproved properties:
United States		162,230			132,720			118,723
Australia		—			—			23,137

Total unproved properties		162,230			132,720			141,860

Total natural gas and oil properties		507,272			445,820			450,963
Less:
Impairment of proved natural gas and oil properties
United States		(187,152	)		(187,152	)		(118,423	)
Australia		—			—			(604	)
Accumulated depreciation, depletion and amortization		(105,447	)		(96,315	)		(79,985	)

Net capitalized costs	$	214,673		$	162,353		$	251,951

Pursuant to authoritative guidance for accounting for asset retirement obligations, net capitalized costs include related asset retirement costs of approximately $5.4 million, $4.4 million and $3.9 million at December 31, 2010, 2009 and 2008, respectively.

The Company sold its remaining Australian Assets in July 2009. See Note 3, “Property, Plant and Equipment.”

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Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

The following table sets forth costs incurred related to the Company’s natural gas and oil activities for the years ended December 31, 2010, 2009 and 2008:


	United States			Australia			Total
	(in thousands)
For the year ended December 31, 2010:
Unproved property acquisition	$	54,799		$	—		$	54,799
Unproved property divestment		(25,289	)		—			(25,289	)
Proved property divestment		(4,872	)		—			(4,872	)
Exploration		12,648			—			12,648
Development		24,166			—			24,166

Total costs incurred	$	61,452		$	—		$	61,452


For the year ended December 31, 2009:
Unproved property acquisition	$	13,997		$	14,457		$	28,454
Unproved property divestment		—			(37,594	)		(37,594	)
Proved property divestment		(21,783	)		(604	)		(22,387	)
Exploration		12,731			—			12,731
Development		13,653			—			13,653

Total costs incurred	$	18,598		$	(23,741	)	$	(5,143	)


For the year ended December 31, 2008:
Unproved property acquisition	$	32,590		$	8,835		$	41,425
Unproved property - GeoStar settlement		39,606			(9,015	)		30,591
Proved property - GeoStar settlement		882			—			882
Exploration		26,050			—			26,050
Development		34,799			—			34,799

Total costs incurred	$	133,927		$	(180	)	$	133,747

Results of Operations for Oil and Gas Producing Activities

The following table sets forth the Company’s results of operations for oil and gas producing activities for the periods indicated:


	For the Year Ended December 31,
	2010			2009			2008
	(in thousands, except per Mcfe data)
Natural gas and oil sales, including unrealized natural gas hedge	$	42,768		$	32,869		$	63,219
Production expenses		(11,703	)		(8,558	)		(10,893	)
Impairment of natural gas and oil properties		—			(68,729	)		(14,217	)
Depreciation, depletion and amortization		(9,131	)		(16,331	)		(24,310	)

Results of producing activities	$	21,934		$	(60,749	)	$	13,799

Depreciation, depletion and amortization per Mcfe	$	1.19		$	1.76		$	2.86

The results of producing activities exclude interest charges and general corporate expenses and represent United States activities only due to no producing operations activities in Australia during 2010, 2009 and 2008.

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In accordance with current authoritative guidance, estimates of the Company’s proved reserves and future net revenues are made using benchmark prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month prices for natural gas and oil and were used in the Company’s reserve valuation as of December 31, 2010 and 2009. The following table provides the key natural gas and oil prices used as of the periods indicated to calculate reserves:


	As of December 31,
	2010		2009
Natural gas (per MMBtu):
Henry Hub	$	4.38	$	3.87
Katy Hub	$	4.32	$	3.68
CIG	$	3.95	$	3.04
Columbia Gas Appalachia	$	4.50	$	4.05
Oil (per Bbl)	$	75.96	$	57.65

These prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve report but are adjusted by lease in accordance with sales contracts and for energy content, quality, transportation, compression and gathering fees and regional price differentials. Estimated quantities of proved reserves and future net revenues are affected by natural gas prices and oil prices, which have fluctuated significantly in recent years.

Net Proved and Proved Developed Reserve Summary

Reserve Estimation. The reserve information presented below is based on estimates of net proved reserves as of December 31, 2010, 2009, and 2008 that were prepared by NSAI. A copy of NSAI’s summary reserve report is included as Exhibit 99.1 to this Form 10-K. Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and governmental regulations (i.e., prices and costs as of the date the estimate is made). Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. The Company’s proved developed and proved undeveloped reserves are located only in the U.S.

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The following table sets forth changes in estimated net proved and proved developed and undeveloped reserves for the years ended December 31, 2010, 2009 and 2008:


	Natural Gas (MMcf) (1)			Oil (MBbl) (2)			MMcfe (1) Equivalents (3)
Proved reserves as of December 31, 2007		54,822			9			54,876

2008 Activity:
Extensions and discoveries		15,186			—			15,186
Revisions of previous estimates (4)		2,159			8			2,207
Production		(8,482	)		(5	)		(8,512	)

Proved reserves as of December 31, 2008		63,685			12			63,757

2009 Activity:
Extensions and discoveries		1,716			56			2,052
Revisions of previous estimates (5)		(7,603	)		3			(7,585	)
Production		(9,266	)		(4	)		(9,290	)

Proved reserves as of December 31, 2009		48,532			67			48,934

2010 Activity:
Extensions and discoveries		5,639			67			6,039
Revisions of previous estimates		2,837			(44	)		2,576
Production		(7,593	)		(10	)		(7,654	)
Purchases in place		1,527			6			1,565
Sales in place		(1,050	)		(25	)		(1,200	)

Proved reserves as of December 31, 2010		49,892			61			50,260

(1)	Million cubic feet or million cubic feet equivalent, as applicable

(2)	Thousand barrels

(3)	Oil volumes have been converted to equivalent natural gas volumes using a conversion factor of six cubic feet of natural gas to one barrel of oil.

(4)

The 2008 upward revision of previous estimates is primarily attributable to performance revisions in the Hilltop area of east Texas reduced by the impact of lower natural gas prices. Natural gas prices decreased approximately 25% from December 31, 2007 to December 31, 2008, resulting in a decrease in proved reserves of approximately 10,754 MMcf.

(5)

The 2009 downward revision of previous estimates of natural gas is primarily attributable to lower natural gas prices. The December 31, 2009 reserve report utilized a 12-month unweighted first-day-of-the-month price compared to the utilization of the year end spot price on December 31, 2008 resulting in a decrease in price of approximately 35% and a decrease in proved reserves of approximately 11,300 MMcf from December 31, 2008 to December 31, 2009. Natural gas negative impact was partially offset by upward performance revisions, primarily in the Hilltop area of East Texas.

F-50

Proved Developed and Undeveloped Reserves


	Natural Gas (MMcf) (1)		Oil (MBbl) (2)		MMcfe (1) Equivalents (3)

December 31, 2008
Proved developed reserves		40,239		12		40,311
Proved undeveloped reserves		23,446		—		23,446

Total		63,685		12		63,757


December 31, 2009
Proved developed reserves		35,527		34		35,731
Proved undeveloped reserves		13,005		33		13,203

Total		48,532		67		48,934


December 31, 2010
Proved developed reserves		41,572		45		41,842
Proved undeveloped reserves		8,320		16		8,416

Total		49,892		61		50,258

(1)	Million cubic feet or million cubic feet equivalent, as applicable

(2)	Thousand barrels

(3)	Oil volumes have been converted to equivalent natural gas volumes using a conversion factor of six cubic feet of natural gas to one barrel of oil.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes that such information is essential for a proper understanding and assessment of the data presented.

For the year ended December 31, 2010 and 2009, future cash inflows were computed using the 12-month unweighted arithmetic average of the first-day-of-the-month prices for natural gas and oil relating to the Company’s proved reserves to the year-end quantities of those reserves. For the years ended December 31, 2010 and 2009, calculations were made using prices of $4.38 per MMBtu and $3.87 per MMBtu for natural gas, respectively, and $75.96 per barrel and $57.65 per barrel for oil, respectively. For the year ended December 31, 2008, future cash inflows were computed using end of year pricing of natural gas and oil allowed under previous guidance relating to the Company’s proved reserves to the year-end quantities of those reserves. For the year ended December 31, 2008, the calculations were made using prices of $5.71 per MMBtu for natural gas and $41.00 per barrel for oil. These prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve report but are adjusted by lease in accordance with sales contracts and for energy content, quality, transportation, compression and gathering fees and regional price differentials. The Company also includes its standard overhead charges pursuant to the respective property joint operating agreements in the calculation of its future cash flows.

The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate could also result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or changes in regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

F-51

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized. The Company does not currently estimate any future income tax expense based on the future pre-tax net cash flows.

A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is presented below:


	United States
	(in thousands)

December 31, 2008:
Future cash inflows	$	291,004
Future production costs		(72,265	)
Future development costs		(51,274	)
Future income taxes (1)		—

Future net cash flows		167,465
10% annual discount for estimated timing of cash flows		(57,376	)

Standardized measure of discounted future cash flows	$	110,089


December 31, 2009:
Future cash inflows	$	148,002
Future production costs		(57,949	)
Future development costs		(24,099	)
Future income taxes (1)		—

Future net cash flows		65,954
10% annual discount for estimated timing of cash flows		(20,331	)

Standardized measure of discounted future cash flows	$	45,623


December 31, 2010:
Future cash inflows	$	180,677
Future production costs		(61,249	)
Future development costs		(20,699	)
Future income taxes (1)		—

Future net cash flows		98,729
10% annual discount for estimated timing of cash flows		(31,447	)

Standardized measure of discounted future cash flows	$	67,282

(1)	Based on current tax carry forwards and current and future property tax basis, no future taxes payable have been included in the determination of discounted future net cash flows.

F-52

Changes in Standardized Measure of Discounted Future Net Cash Flows

The principal sources of changes in the standardized measure of future net cash flows are as follows:


	United States
	(in thousands)

December 31, 2007	$	132,232
Extensions and discoveries, less related costs		22,634
Sale of natural gas and oil, net of production costs		(45,796	)
Revisions of previous quantity estimates		5,241
Net change in income tax		—
Net change in prices and production costs		(48,698	)
Accretion of discount		13,223
Development costs incurred		20,056
Net change in estimated future development costs		4,850
Change in production rates (timing) and other		6,347

December 31, 2008		110,089
Extensions and discoveries, less related costs		2,782
Sale of natural gas and oil, net of production costs		(32,078	)
Revisions of previous quantity estimates		(8,982	)
Net change in income tax		—
Net change in prices and production costs		(63,016	)
Accretion of discount		11,009
Development costs incurred		12,368
Net change in estimated future development costs		12,497
Change in production rates (timing) and other		954

December 31, 2009		45,623
Extensions and discoveries, less related costs		10,277
Sale of natural gas and oil, net of production costs		(19,851	)
Purchases of reserves in place		544
Sales of reserves in place		(1,966	)
Revisions of previous quantity estimates		3,133
Net change in income tax		—
Net change in prices and production costs		16,970
Accretion of discount		4,307
Development costs incurred		6,357
Net change in estimated future development costs		1,621
Change in production rates (timing) and other		267

December 31, 2010	$	67,282

F-53

Attached files

GASTAR EXPLORATION, INC. Reports

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