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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

 

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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2011

OR

 

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

FOR THE TRANSITION PERIOD FROM              TO             .

Commission File Number: 001-32714

 

 

GASTAR EXPLORATION LTD.

GASTAR EXPLORATION USA, INC.

(Exact name of registrant as specified in its charter)

 

 

 

Alberta, Canada		98-0570897
Delaware		38-3531640
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
1331 Lamar Street, Suite 650
Houston, Texas 77010		77010
(Address of principal executive offices)		(ZIP Code)

(713) 739-1800

(Registrant’s telephone number, including area code)

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

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

 

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

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

Total number of outstanding common shares, no par value per share, as of August 3, 2011 was:

 

Gastar Exploration Ltd.		64,762,952 shares of common stock
Gastar Exploration USA, Inc.		750 shares of common stock

 

 

 

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GASTAR EXPLORATION LTD.

QUARTERLY REPORT ON FORM 10-Q

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2011

TABLE OF CONTENTS

 

				Page
PART I – FINANCIAL INFORMATION
Item 1.		Financial Statements
		Gastar Exploration Ltd. Condensed Consolidated Balance Sheets as of June 30, 2011 and December  31, 2010			1
		Gastar Exploration Ltd. Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2011 and 2010			2
		Gastar Exploration Ltd. Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010			3
		Gastar Exploration USA, Inc. Condensed Consolidated Balance Sheets as of June  30, 2011 and December 31, 2010			4
		Gastar Exploration USA, Inc. Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2011 and 2010			5
		Gastar Exploration USA, Inc. Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010			6
		Notes to the Condensed Consolidated Financial Statements (unaudited)			7
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			24
Item 3.		Quantitative and Qualitative Disclosures About Market Risk			34
Item 4.		Controls and Procedures			35
PART II – OTHER INFORMATION
Item 1.		Legal Proceedings			36
Item 1A.		Risk Factors			36
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			37
Item 3.		Defaults Upon Senior Securities			37
Item 4.		(Removed and Reserved)			37
Item 5.		Other Information			37
Item 6.		Exhibits			37
SIGNATURES					39

Unless otherwise indicated or required by the context, (i) “Gastar,” the “Company,” “we,” “us,” “our” and similar terms refer collectively to Gastar Exploration Ltd. and its subsidiaries, including Gastar Exploration USA, Inc., and predecessors, (ii) “Gastar USA” refers to Gastar Exploration USA, Inc., our first-tier subsidiary and primary operating company, (iii) “Parent” refers solely to Gastar Exploration Ltd., (iv) all dollar amounts appearing in this report on Form 10-Q are stated in United States dollars (“U.S. dollars”) and (v) all financial data included in this report have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”).

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

 

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Glossary of Terms

 

Bbl		Barrel of oil
bbl/d		Barrels of oil per day
Btu		British thermal unit
CBM		Coal bed methane
FASB		Financial Accounting Standards Board
GAAP		Accounting principles generally accepted in the United States of America
MBbl		One million barrels of oil
Mcf		One thousand cubic feet of natural gas
Mcf/d		One thousand cubic feet of natural gas per day
MMBtu/d		One million British thermal units per day
MMcf		One million cubic feet of natural gas
MMcf/d		One million cubic feet of natural gas per day
Mcfe		One thousand cubic feet of natural gas equivalent
MMcfe		One million cubic feet of natural gas equivalent
MMcfe/d		One million cubic feet of natural gas equivalent per day
psi		Pound per square inch

 

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PART I. FINANCIAL INFORMATION

Item  1. Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

 

		June 30, 2011				December 31, 2010
		(Unaudited)
		(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	5,495			$	7,439
Accounts receivable, net of allowance for doubtful accounts of $561 and $571, respectively			6,333				4,034
Commodity derivative contracts			9,708				10,229
Prepaid expenses			611				1,191
Total current assets			22,147				22,893
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, excluded from amortization			157,879				162,230
Proved properties			391,030				345,042
Total natural gas and oil properties			548,909				507,272
Furniture and equipment			1,449				1,175
Total property, plant and equipment			550,358				508,447
Accumulated depreciation, depletion and amortization			(300,435	)			(293,332	)
Total property, plant and equipment, net			249,923				215,115
OTHER ASSETS:
Restricted cash			50				50
Commodity derivative contracts			5,650				8,482
Deferred charges, net			393				508
Advances to operators and other assets			728				304
Total other assets			6,821				9,344
TOTAL ASSETS		$	278,891			$	247,352
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable		$	8,697			$	8,294
Revenue payable			4,567				4,331
Accrued interest			129				138
Accrued drilling and operating costs			4,724				1,490
Advances from non-operators			11,784				783
Commodity derivative contracts			817				1,991
Commodity derivative premium payable			4,144				3,451
Accrued litigation settlement liability			2,192				3,164
Other accrued liabilities			2,011				2,024
Total current liabilities			39,065				25,666
LONG-TERM LIABILITIES:
Long-term debt			8,000				—
Commodity derivative contracts			1,255				1,521
Commodity derivative premium payable			2,590				4,725
Accrued litigation settlement liability			—				800
Asset retirement obligation			7,682				7,249
Total long-term liabilities			19,527				14,295
Commitments and contingencies (Note 12)
SHAREHOLDERS’ EQUITY:
Common stock, no par value; unlimited shares authorized; 64,778,274 and 64,179,115 shares issued and outstanding at June 30, 2011 and December 31, 2010, respectively			316,346				316,346
Additional paid-in capital			24,205				23,200
Accumulated deficit			(133,964	)			(132,155	)
Total shareholders’ equity			206,587				207,391
Non-controlling interest:
Preferred stock of subsidiary, aggregate liquidation preference $16,268 and $0 at June 30, 2011 and December 31, 2010, respectively			13,712				—
Total equity			220,299				207,391
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$	278,891			$	247,352

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

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2011				2010				2011				2010
		(in thousands, except share and per share data)
REVENUES:
Natural gas and oil revenues		$	8,514			$	6,737			$	18,542			$	13,495
Unrealized natural gas hedge gain (loss)			502				(972	)			(1,397	)			8,406
Total revenues			9,016				5,765				17,145				21,901
EXPENSES:
Production taxes			118				93				227				216
Lease operating expenses			1,875				1,914				3,582				3,657
Transportation, treating and gathering			1,123				1,094				2,226				2,343
Depreciation, depletion and amortization			2,991				1,664				7,103				3,395
Accretion of asset retirement obligation			129				96				254				191
General and administrative expense			2,596				3,944				5,476				7,776
Total expenses			8,832				8,805				18,868				17,578
INCOME (LOSS) FROM OPERATIONS			184				(3,040	)			(1,723	)			4,323
OTHER INCOME (EXPENSE):
Interest expense			(31	)			(20	)			(63	)			(98	)
Investment income and other			3				548				5				1,340
Unrealized warrant derivative gain			—				55				—				203
Foreign transaction gain			1				16				3				335
INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES			157				(2,441	)			(1,778	)			6,103
Provision for income tax expense (benefit)			—				57				—				(792	)
NET INCOME (LOSS)			157				(2,498	)			(1,778	)			6,895
Dividend on preferred stock attributable to non-controlling interest			31				—				31				—
NET INCOME (LOSS) ATTRIBUTABLE TO GASTAR EXPLORATION LTD.		$	126			$	(2,498	)		$	(1,809	)		$	6,895
NET INCOME (LOSS) PER COMMON SHARE ATTRIBUTABLE TO GASTAR EXPLORATION LTD. COMMON SHAREHOLDERS:
Basic		$	0.00			$	(0.05	)		$	(0.03	)		$	0.14
Diluted		$	0.00			$	(0.05	)		$	(0.03	)		$	0.14
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic			63,134,109				49,042,874				63,079,475				49,020,072
Diluted			63,723,093				49,042,874				63,079,475				49,529,357

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

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

		For the Six Months  Ended June 30,
		2011				2010
		(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	(1,778	)		$	6,895
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			7,103				3,395
Stock-based compensation			1,243				1,639
Unrealized natural gas hedge (gain) loss			1,397				(8,406	)
Realized loss (gain) on derivative contracts			(871	)			1,763
Amortization of deferred financing costs and debt discount			128				157
Accretion of asset retirement obligation			254				191
Unrealized warrant derivative gain			—				(203	)
Dividend on preferred stock attributable to non-controlling interest			(31	)			—
Changes in operating assets and liabilities:
Accounts receivable			(625	)			1,615
Commodity derivative contracts			(54	)			1,252
Prepaid expenses			388				232
Accrued taxes payable			—				(1,245	)
Accounts payable and accrued liabilities			555				(2,151	)
Net cash provided by operating activities			7,709				5,134
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of natural gas and oil properties			(39,074	)			(24,591	)
Advances to operators			(3,155	)			—
Proceeds from sale of natural gas and oil properties			—				19,199
Proceeds from non-operators			11,001				(686	)
Purchase of furniture and equipment			(274	)			(142	)
Purchase of term deposit			—				(4,855	)
Net cash used in investing activities			(31,502	)			(11,075	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility			20,000				8,000
Repayment of revolving credit facility			(12,000	)			—
Repayment of short-term loan			—				(17,000	)
Proceeds from issuance of preferred stock, net of issuance costs			14,000				—
Deferred financing charges			(13	)			—
Other			(138	)			(103	)
Net cash provided by (used in) financing activities			21,849				(9,103	)
NET DECREASE IN CASH AND CASH EQUIVALENTS			(1,944	)			(15,044	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD			7,439				21,866
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	5,495			$	6,822

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

 

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GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

 

		June 30, 2011				December 31, 2010
		(Unaudited)
		(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	5,444			$	7,401
Accounts receivable, net of allowance for doubtful accounts of $561 and $571, respectively			6,333				4,034
Commodity derivative contracts			9,708				10,229
Prepaid expenses			516				999
Total current assets			22,001				22,663
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, excluded from amortization			157,879				162,230
Proved properties			391,022				345,034
Total natural gas and oil properties			548,901				507,264
Furniture and equipment			1,449				1,175
Total property, plant and equipment			550,350				508,439
Accumulated depreciation, depletion and amortization			(300,428	)			(293,325	)
Total property, plant and equipment, net			249,922				215,114
OTHER ASSETS:
Restricted cash			25				25
Commodity derivative contracts			5,650				8,482
Deferred charges, net			393				508
Advances to operators and other assets			728				304
Total other assets			6,796				9,319
TOTAL ASSETS		$	278,719			$	247,096
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable		$	8,650			$	8,288
Revenue payable			4,567				4,331
Accrued interest			129				138
Accrued drilling and operating costs			4,724				1,490
Advances from non-operators			11,784				783
Commodity derivative contracts			817				1,991
Commodity derivative premium payable			4,144				3,451
Accrued litigation settlement liability			2,192				3,164
Other accrued liabilities			2,005				2,017
Total current liabilities			39,012				25,653
LONG-TERM LIABILITIES:
Long-term debt			8,000				—
Commodity derivative contracts			1,255				1,521
Commodity derivative premium payable			2,590				4,725
Accrued litigation settlement liability			—				800
Asset retirement obligation			7,675				7,243
Due to parent			25,866				25,193
Total long-term liabilities			45,386				39,482
Commitments and contingencies (Note 12)
STOCKHOLDERS’ EQUITY:
Preferred stock, $0.01 par value; 10,000,000 shares authorized; 650,728 and 0 shares issued and outstanding at June 30, 2011 and December 31, 2010, respectively, with liquidation preference of $25.00 per share			7				—
Common stock, no par value; 1,000 shares authorized; 750 shares issued and outstanding			240,431				240,431
Additional paid-in capital			13,705				—
Accumulated deficit			(59,822	)			(58,470	)
Total stockholders’ equity			194,321				181,961
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	278,719			$	247,096

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

 

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GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2011				2010				2011				2010
		(in thousands, except share and per share data)
REVENUES:
Natural gas and oil revenues		$	8,514			$	6,737			$	18,542			$	13,495
Unrealized natural gas hedge gain (loss)			502				(972	)			(1,397	)			8,406
Total revenues			9,016				5,765				17,145				21,901
EXPENSES:
Production taxes			118				93				227				216
Lease operating expenses			1,874				1,913				3,581				3,656
Transportation, treating and gathering			1,123				1,094				2,226				2,343
Depreciation, depletion and amortization			2,991				1,664				7,103				3,395
Accretion of asset retirement obligation			129				96				254				191
General and administrative expense			2,414				3,658				5,113				6,973
Total expenses			8,649				8,518				18,504				16,774
INCOME (LOSS) FROM OPERATIONS			367				(2,753	)			(1,359	)			5,127
OTHER INCOME (EXPENSE):
Interest expense			(30	)			(19	)			(62	)			(45	)
Investment income and other			3				546				97				1,339
Foreign transaction gain			1				17				3				335
INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES			341				(2,209	)			(1,321	)			6,756
Provision for income tax expense (benefit)			—				57				—				(792	)
NET INCOME (LOSS)			341				(2,266	)			(1,321	)			7,548
Dividend on preferred stock			31				—				31				—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDER		$	310			$	(2,266	)		$	(1,352	)		$	7,548

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

 

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GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

		For the Six Months Ended June 30,
		2011				2010
		(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	(1,352	)		$	7,548
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			7,103				3,395
Stock-based compensation			1,243				1,639
Unrealized natural gas hedge (gain) loss			1,397				(8,406	)
Realized loss (gain) on derivative contracts			(871	)			1,763
Amortization of deferred financing costs and debt discount			128				121
Accretion of asset retirement obligation			254				191
Changes in operating assets and liabilities:
Accounts receivable			(625	)			1,614
Commodity derivative contracts			(54	)			1,252
Prepaid expenses			291				117
Accrued taxes payable			—				(1,245	)
Accounts payable and accrued liabilities			515				(1,810	)
Net cash provided by operating activities			8,029				6,179
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of natural gas and oil properties			(39,074	)			(24,591	)
Advances to operators			(3,155	)
Proceeds from sale of natural gas and oil properties			—				19,199
Proceeds from non-operators			11,001				(686	)
Purchase of furniture and equipment			(274	)			(142	)
Purchase of term deposit			—				(4,855	)
Net cash used in investing activities			(31,502	)			(11,075	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility			20,000				8,000
Repayment of revolving credit facility			(12,000	)			—
Proceeds from issuance of preferred stock, net of issuance costs			14,000				—
Deferred financing charges			(13	)			—
Dividend to parent, net			(571	)			(18,192	)
Other			100				51
Net cash provided by (used in) financing activities			21,516				(10,141	)
NET DECREASE IN CASH AND CASH EQUIVALENTS			(1,957	)			(15,037	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD			7,401				21,808
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	5,444			$	6,771

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

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Description of Business

Gastar Exploration Ltd. is an independent energy company engaged in the exploration, development and production of natural gas and oil in the United States (“U.S.”). Gastar Exploration Ltd.’s principal business activities include the identification, acquisition, and subsequent exploration and development of natural gas and oil properties with an emphasis on 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 Marcellus Shale in the Appalachian area of West Virginia and central and southwestern Pennsylvania and in the deep Bossier gas play in the Hilltop area of East Texas. Gastar Exploration Ltd. also conducts limited CBM development activities within the Powder River Basin of Wyoming and Montana.

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

2. Summary of Significant Accounting Policies

The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2010 (“2010 Form 10-K”) filed with the SEC. Please refer to the notes to the financial statements included in the Company’s 2010 Form 10-K and to Exhibit 99.1 to the Company’s Current Report on Form 8-K dated May 26, 2011 for additional details of the Company’s financial condition, results of operations and cash flows. All material items included in those notes have not changed except as a result of normal transactions in the interim or as disclosed within this report.

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

The unaudited interim condensed consolidated financial statements of the Company and Gastar USA included herein are stated in U.S. dollars unless otherwise noted and were prepared from the records of the Company and Gastar USA by management in accordance with U.S. GAAP applicable to interim financial statements and reflect all normal and recurring adjustments, which are, in the opinion of management, necessary to provide a fair presentation of the results of operations and financial position for the interim periods. Such financial statements conform to the presentation reflected in the Company’s 2010 Form 10-K and to Exhibit 99.1 to the Company’s Current Report on Form 8-K dated May 26, 2011. The current interim period reported herein should be read in conjunction with the financial statements and accompanying notes, including Item 8. “Financial Statements and Supplementary Data, Note 2 - Summary of Significant Accounting Policies” included in the Company’s 2010 Form 10-K and to Exhibit 99.1 to the Company’s Current Report on Form 8-K dated May 26, 2011.

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

 

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value of estimated future net cash flows.

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

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

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

The results of operations for the three and six months ended June 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011. In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these condensed consolidated financial statements, as appropriate.

Recent Accounting Developments

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

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

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

Business Combinations. In December 2010, the FASB’s Emerging Issues Task Force issued an amendment to previously issued guidance regarding the pro forma revenue and earnings disclosure requirements for business combinations. The amendments specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures under current guidance to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. This guidance is effective

 

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prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. Earlier application is permitted. The adoption of this guidance did not impact our operating results, financial position or cash flows.

3. Property, Plant and Equipment

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

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

 

		June 30, 2011				December 31, 2010
		(in thousands)
Unproved properties, excluded from amortization:
Drilling in progress costs		$	11,312			$	17,603
Acreage acquisition costs			129,035				126,388
Capitalized interest			17,532				18,239
Total unproved properties excluded from amortization		$	157,879			$	162,230

Management’s ceiling test evaluations for the six months ended June 30, 2011 and 2010 did not result in an impairment of proved properties. The ceiling test evaluations utilized a historical 12-month un-weighted average of the first-day-of-the-month Henry Hub natural gas price of $4.21 per MMBtu and $4.10 per MMBtu for the six months ended June 30, 2011 and 2010, respectively.

Atinum Joint Venture

In September 2010, Gastar USA entered into a joint venture (the “Atinum Joint Venture”) pursuant to a purchase and sale agreement with an affiliate of Atinum Partners Co., Ltd. (“Atinum”), a Korean investment firm. Pursuant to the agreement, at the closing of the transactions on November 1, 2010, Gastar USA assigned to Atinum an initial 21.43% interest in all of its existing Marcellus Shale assets in West Virginia and Pennsylvania, which consisted of approximately 37,600 gross (34,200 net) acres and a 50% working interest in 16 producing shallow conventional wells and one non-producing vertical Marcellus Shale well. Atinum paid Gastar USA approximately $30.0 million in cash at the closing and will pay an additional $40.0 million of future drilling obligations over time in the form of a “drilling carry.” Upon completion of the funding of the drilling carry, Gastar USA will make additional assignments to Atinum, as necessary, so Atinum will own a 50% interest in the 34,200 net acres of Marcellus Shale rights initially owned by Gastar USA. The terms of the drilling carry require Atinum to fund its ultimate 50% share of drilling, completion and infrastructure costs along with 75% of Gastar USA’s ultimate 50% share of those same costs until the $40.0 million drilling carry has been satisfied. As of June 30, 2011, approximately $32.9 million of drilling carry obligation remained outstanding.

The Atinum Joint Venture is pursuing an initial three-year development program that calls for the partners to drill a minimum of 12 horizontal wells in 2011 and 24 horizontal wells in each of 2012 and 2013. 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 this initial AMI, Gastar USA will act as operator and is obligated to offer any future lease acquisitions within the AMI to Atinum on a 50/50 basis, and Atinum will pay Gastar USA on an annual basis an amount equal to 10% of lease bonuses and third party leasing costs up to $20.0 million and 5% of such costs on activities above $20.0 million. Until June 30, 2011, Atinum had the right to participate in any leasehold acquisitions made by Gastar USA outside of the initial AMI and within West Virginia or Pennsylvania on terms identical to those governing the existing Atinum Joint Venture.

As of June 30, 2011, total cash consideration received by Gastar USA pursuant to the Atinum Joint Venture was approximately $37.1 million, $30.0 million of which was received upon closing and $7.1 million of drilling

 

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carry. The $30.0 million received upon closing 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 an acquisition of undeveloped leasehold in the Marcellus Shale concentrated in Preston, Tucker, Pocahontas, Randolph and Pendleton Counties, West Virginia, including a gathering system comprised of 41 miles of four and six inch steel pipe, a salt water disposal well and five conventional producing wells. This acreage is not included in the Atinum Joint Venture and the counties in which the acquired assets are located are not part of the initial AMI.

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 on the acquisition date.

4. Long-Term Debt

Amended and Restated Revolving Credit Facility

On October 28, 2009, Gastar USA, together with Parent and Subsidiary Guarantors (as defined in the Revolving Credit Facility), and the lenders, administrative agent and letter of credit issuer party thereto, entered into an amended and restated credit facility, amending and restating in its entirety the original revolving credit facility (as amended and restated, the “Revolving Credit Facility”). The Revolving Credit Facility provided an initial borrowing base of $47.5 million, with borrowings bearing interest, at Gastar USA’s election, at the prime rate or LIBO rate plus an applicable margin. Pursuant to the Revolving Credit Facility, the applicable interest rate margin varies from 1.0% to 2.0% in the case of borrowings based on the prime rate and from 2.5% to 3.5% in the case of borrowings based on LIBO rate, depending on the utilization percentage in relation to the borrowing base. An annual commitment fee of 0.50% is payable quarterly based on the unutilized balance of the borrowing base. The Revolving Credit Facility has a scheduled maturity date of January 2, 2013.

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

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

 

•

Restrictions on liens;

 

•

Restrictions on incurring other indebtedness without the lenders’ consent;

 

•

Restrictions on dividends and other restricted payments;

 

•

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

 

•

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

 

•

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

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

 

•

Failure to make payments under the Revolving Credit Facility;

 

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•

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

 

•

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

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

Following the scheduled semi-annual borrowing base redetermination in May 2010, on June 24, 2010, Gastar USA, together with the other parties thereto, entered into the Second Amendment to the Amended and Restated Credit Agreement (the “Second Amendment”) amending that certain Amended and Restated Credit Agreement dated October 28, 2009 (as amended by that certain Consent and First Amendment to Amended and Restated Credit Agreement dated November 20, 2009, the Second Amendment and the Third Amendment (as defined below), the “Credit Agreement”) . The Second Amendment amended the Revolving Credit Facility, by, among other things, (i) allowing Gastar USA to hedge up to 80% of the proved developed producing (“PDP”) reserves reflected in its reserve report using hedging other than floors and protective spreads, (ii) allowing Gastar USA to present to the administrative agent a report showing any PDP additions resulting from new wells or the conversion of proved developed non-producing reserves to PDP reserves since the last reserve report in order to hedge the revised PDP reserves, and (iii) removing the limitations on hedging using floors and protective spreads.

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

As of June 30, 2011, the Revolving Credit Facility had a borrowing base of $50.0 million, with $8.0 million of borrowings outstanding and availability of $42.0 million. Borrowing base redeterminations are scheduled semi-annually in May and November of each calendar year, with the next redetermination scheduled for November 2011. Gastar USA and the lenders may each request one additional unscheduled redetermination annually.

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

Other Debt

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

5. Fair Value Measurements

The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized non-financial assets and liabilities, such as asset retirement obligations and other property and equipment, at fair value on a non-recurring basis. For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements to assess the inputs used to develop these measurements. Since none of the Company’s non-financial assets and liabilities were impaired during the period-ended June 30, 2011, and no other fair value measurements are required to be recognized on a non-recurring basis, no additional disclosures are provided at June 30, 2011.

As defined in the guidance, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use

 

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in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of the fair value hierarchy are as follows:

 

•

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

 

•

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

 

•

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

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

 

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

 

		Fair value as of June 30, 2011
		Level 1				Level 2				Level 3				Total
		(in thousands)
Assets:
Cash and cash equivalents		$	5,495			$	—			$	—			$	5,495
Restricted cash			50				—				—				50
Commodity derivative contracts			—				—				15,358				15,358
Liabilities:
Commodity derivative contracts			—				—				(2,072	)			(2,072	)
Total		$	5,545			$	—			$	13,286			$	18,831
		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

 

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

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2011				2010				2011				2010
		(in thousands)
Balance at beginning of period		$	13,069			$	15,011			$	15,199			$	7,638
Total gains (losses) (realized or unrealized):
included in earnings			2,221				675				2,782				9,203
included in other comprehensive income			—				—				—				—
Purchases			—				—				—				—
Issuances			—				—				—				—
Settlements (1)			(2,004	)			(2,454	)			(4,695	)			(3,609	)
Transfers in and (out) of Level 3			—				—				—				—
Balance at end of period		$	13,286			$	13,232			$	13,286			$	13,232
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets still held at June 30, 2011 and 2010		$	502			$	(917	)		$	(1,397	)		$	8,609

 

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

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

6. Derivative Instruments and Hedging Activity

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

All derivative contracts are carried at their fair value on the balance sheet and all unrealized gains and losses are recorded in the statement of operations in unrealized natural gas hedge gain (loss), while realized gains and losses related to contract settlements are recognized in natural gas and oil revenues. For the three and six months ended June 30, 2011, the Company reported an unrealized gain of $502,000 and an unrealized loss of $1.4 million, respectively, in the consolidated statement of operations related to the change in the fair value of its commodity derivative instruments. For the three and six months ended June 30, 2010, the Company reported an unrealized loss of $972,000 and an unrealized gain of $8.4 million, respectively, in the consolidated statement of operations related to the change in the fair value of its commodity derivative instruments.

 

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As of June 30, 2011, 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			14,342				2,638,000			$	—			$	6.07			$	4.14			$	—
2011		Costless three-way collar			3,262				600,000				—				6.00				4.00				7.00
2011		Fixed price swap			2,000				368,000				6.11				—				—				—
2011		Basis - CIG (1)			800				147,200				(1.21	)			—				—				—
2012		Put spread			13,028				4,770,420				—				6.00				4.00				—
2012		Costless three-way collar			5,410				1,979,580				—				6.00				4.00				7.39
2012		Fixed price swap			2,000				732,000				5.00				—				—				—
2013		Costless three-way collar			2,500				912,500				—				5.00				4.00				6.45
2013		Fixed price swap			2,500				912,500				5.40				—				—				—

 

(1)	Inside FERC Colorado Interstate Gas, Rocky Mountains

As of June 30, 2011, all of the Company’s economic derivative hedge positions were with a multinational energy company or large financial institutions, which are not known to the Company to be in default on their derivative positions. Credit support for the Company’s open derivatives at June 30, 2011 is provided under the Revolving Credit Facility through inter-creditor agreements or open credit accounts of up to $5.0 million. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contains credit-risk related contingent features.

In conjunction with certain derivative hedging activity, the Company deferred the payment of certain put premiums for the production month period July 2010 through December 2012. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company began amortizing the deferred put premium liabilities during July 2010.

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

 

		June 30, 2011				December 31, 2010
		(in thousands)
Current commodity derivative premium payable		$	4,144			$	3,451
Long-term commodity derivative premium payable			2,590				4,725
Total unamortized put premium liabilities		$	6,734			$	8,176

 

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

 

		June 30, 2011
		(in thousands)
July - December 2011		$	2,009
January - December 2012			4,725
Total unamortized put premium liabilities		$	6,734

Warrants

The Parent reclassified the fair value of its warrants to purchase common shares, which had exercise price reset features, from equity to liability status as if these warrants were treated as a derivative liability since their date of issue in June 2008. On January 1, 2009, Parent reclassified from additional paid-in capital, as a cumulative effect adjustment, $5.4 million to beginning retained earnings and did not recognize any value to common stock warrant liability for representing the fair value of such warrants on such date. The fair value of these warrants to purchase common stock was zero as of June 30, 2011. The Parent recognized $55,000 and $203,000 in unrealized gains in other income for the change in fair value of these warrants for the three and six months ended June 30, 2010, respectively.

The following warrants to purchase common shares were outstanding as of June 30, 2011:

 

Warrants Outstanding				Fair Value (in thousands)				Weighted Price per Share Range				Weighted Average Remaining Life in Years				Average Exercise Price
	2,000,000			$	0				(1	)			0.4				(1	)

 

(1)	The Company did not sell all or substantially all of its East Texas properties by June 11, 2011 and the warrants are exercisable for a six-month period commencing on that date at $15.00 per share. Fair value is based on the Black-Scholes-Merton model for option pricing.

 

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Additional Disclosures about Derivative Instruments and Hedging Activities

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

 

		Fair Values of Derivative Instruments
		Derivative Assets (Liabilities)
				Fair Value
		Balance Sheet Location		June 30, 2011				December 31, 2010
				(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts		Current assets		$	9,708			$	10,229
Commodity derivative contracts		Other assets			5,650				8,482
Commodity derivative contracts		Current liabilities			(817	)			(1,991	)
Commodity derivative contracts		Long-term liabilities			(1,255	)			(1,521	)
Total derivatives not designated as hedging instruments				$	13,286			$	15,199

 

		Amount of Gain (Loss) Recognized in Income on Derivatives
				Amount of Gain (Loss) Recognized in Income on Derivatives
				For the Three Months Ended
		Location of Gain (Loss) Recognized in Income on Derivatives		June 30, 2011				June 30, 2010
				(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts		Unrealized natural gas hedge gain (loss)		$	502			$	(972	)
Warrant derivative		Unrealized warrant derivative gain (loss)			—				55
Total				$	502			$	(917	)
		Amount of Gain (Loss) Recognized in Income on Derivatives
				Amount of Gain (Loss) Recognized in Income on Derivatives
				For the Six Months Ended
		Location of Gain (Loss) Recognized in Income on Derivatives		June 30, 2011				June 30, 2010
				(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts		Unrealized natural gas hedge gain (loss)		$	(1,397	)		$	8,406
Warrant derivative		Unrealized warrant derivative gain (loss)			—				203
Total				$	(1,397	)		$	8,609

7. Capital Stock

Other Share Issuances

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

 

		For the Three Months Ended				For the Six Months Ended
		June 30, 2011				June 30, 2011
Other share issuances:
Restricted common shares granted			—				753,199
Restricted common shares vested			87,035				204,211
Stock options exercised			15,000				15,000
Common shares forfeited (1)			35,028				67,501
Common shares canceled			64,039				101,539

 

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

 

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Shares Reserved

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

 

Common shares reserved for the:
Exercise of stock options			1,053,600
Exercise of warrants			2,000,000
Total common shares reserved			3,053,600

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 June 30, 2011 and December 31, 2010, all of which were held by Parent.

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

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

Gastar USA Preferred Stock

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

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

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

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

During the six months ended June 30, 2011, Gastar USA sold 4,433 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $97,000. Subsequent to June 30, 2011 through August 3, 2011, Gastar USA sold an additional 60,463 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $1.3 million.

 

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

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

 

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

Gastar USA will pay cumulative dividends on the Series A Preferred Stock at a fixed rate of 8.625% per annum of the $25.00 per share liquidation preference. For the quarter ended June 30, 2011, Gastar USA accrued dividends payable of $31,000.

8. Interest Expense

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

 

		For the Three Months Ended								For the Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(in thousands)
Interest expense:
Cash and accrued		$	237			$	85			$	379			$	190
Amortization of deferred financing costs and debt discount			65				61				128				157
Capitalized interest			(271	)			(126	)			(444	)			(249	)
Total interest expense		$	31			$	20			$	63			$	98

9. Related Party Transactions

Chesapeake Energy Corporation

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

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

10. Income Taxes

For the three and six months ended June 30, 2011, the Company did not recognize a current income tax benefit or provision. For the three and six months ended June 30, 2010, the Company recognized a current income

 

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tax expense of $57,000 and a current income tax benefit of $792,000, respectively. The second quarter 2010 income tax expense represented Australian withholding tax on Australian interest income earned during the period. The income tax benefit for the six-month period ended June 30, 2010 is primarily the result of the Australian Taxation Office’s (“ATO”) issuance of an amended assessment of the income tax with respect to the gain on sale of the Company’s Australian assets in July 2009. The issuance of the amended assessment by the ATO represented final resolution in favor of the Company of certain tax issues that could not be resolved until the ATO completed its review of the Australian assets sale in April 2010. The ATO resolution resulted in the recognition of an Australian tax expense benefit of AU$1.3 million ($1.0 million), which was reduced by AU$213,000 ($196,000) of Australian withholding tax on interest income earned on term deposits in Australia from the date of the sale through March 31, 2010.

11. Earnings per Share

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

 

		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2011				2010				2011				2010
		(in thousands, except per share and share data)
Net income (loss) attributable to common shareholders		$	126			$	(2,498	)		$	(1,809	)		$	6,895
Weighted average common shares outstanding - basic			63,134,109				49,042,874				63,079,475				49,020,072
Incremental shares from unvested restricted shares			538,315				—				—				437,453
Incremental shares from outstanding stock options			50,669				—				—				71,832
Weighted average common shares outstanding - diluted			63,723,093				49,042,874				63,079,475				49,529,357
Income (loss) per common share:
Basic		$	0.00			$	(0.05	)		$	(0.03	)		$	0.14
Diluted		$	0.00			$	(0.05	)		$	(0.03	)		$	0.14
Common shares excluded from denominator as anti-dilutive:
Unvested restricted shares			—				179,028				205,693				90,009
Stock options			867,800				905,800				867,800				989,933
Warrants			2,000,000				2,000,000				2,000,000				2,000,000
Total			2,867,800				3,084,828				3,073,493				3,079,942

12. Commitments and Contingencies

Litigation

Navasota Resources L.P. (“Navasota”) vs. First Source Texas, Inc., First Source Gas L.P. (now Gastar Exploration Texas LP) and Gastar Exploration Ltd. (Cause No. 0-05-451) District Court of Leon County, Texas12th Judicial District. This lawsuit, dated October 31, 2005, contends that the Company breached Navasota’s preferential right to purchase 33.33% of the Company’s interest in certain natural gas and oil leases located in Leon and Robertson Counties, which were sold to Chesapeake on November 4, 2005 (the “2005 Transaction”). The preferential right claimed is under an operating agreement dated July 7, 2000. The Company contends, among other things, that Navasota neither properly nor timely exercised any preferential right election it may have had with respect to the 2005 Transaction. In July 2006, the District Court of Leon County, Texas issued a summary judgment in favor of the Company and Chesapeake. Navasota filed a Notice of Appeal to the Tenth Court of Appeals in Waco. Oral argument was heard on September 26, 2007 and the Court of Appeals issued its opinion on January 9, 2008 reversing the trial court’s rulings, rendering judgment in favor of Navasota on its claims for breach of contract and specific performance, and remanding the case for further proceedings on Navasota’s other counts, which include claims for suit to quiet title, trespass to try title, tortuous interference with contract, conversion, money had and

 

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received, and declaratory relief. The Company and Chesapeake filed a motion for rehearing on February 6, 2008, which was denied on March 18, 2008. The Company and Chesapeake filed a joint Petition for Review in the Texas Supreme Court on May 13, 2008. On August 28, 2008, the Texas Supreme Court requested briefing on the merits. On January 9, 2009, the Texas Supreme Court denied the Petition for Review. On January 26, 2009, the Company and Chesapeake jointly filed a motion for rehearing in the Texas Supreme Court on its denial of the Petition for Review. On April 24, 2009, the Texas Supreme Court denied the Petition for Review.

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

On or about June 9, 2009, Navasota filed and served its Fourth Amended Petition, essentially re-pleading its previously-asserted claims against the Company and Chesapeake. Navasota has exercised its rights of specific performance, and Chesapeake assigned leases to Navasota in July 2009. In March 2011, Chesapeake dismissed the cross-claims against the Company, including the claim for rescission, without prejudice to the subsequent refiling of those claims. On April 12, 2011, Navasota filed its Fifth Amended Petition. The Fifth Amended Petition adds a new claim that the Company allegedly has refused to offer Navasota interests in oil and gas leases located within an area of mutual interest, failed to assign Navasota overriding royalty interests, and failed to recognize back-in-after-payout interests.

The case has been set for trial on September 27, 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.

Gastar Exploration Texas L.P. vs. J. Ken Welch d/b/a W-S-M Oil Company, et al; Cause No. 0-09-117 in the 87th Judicial District Court of Leon County, Texas. This lawsuit, filed on March 12, 2009, is a suit for trespass to try title and, in the alternative, to quiet title to an undivided mineral interest under several Company oil and gas leases covering approximately 4,273.7 gross acres (the “Leases”). The Company contends that certain oil and gas leases claimed by the defendants have expired according to their terms and that the defendants’ failure to release those leases constitutes a trespass upon and cloud on the Leases. The Company also contends that the defendants’ continued production of oil from wells located on the land in question is a trespass to real property for which the Company is entitled to receive damages. The defendants have responded with a general denial and produced a portion of the documents the Company sought in its request for production of documents. They have also served

 

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their own requests for admissions and production of documents, to which the Company has responded. After repeated demands, the defendants produced 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. 1 well located in Leon County. The parties attended mediation but no settlement was reached. The defendants were deposed in March 2011. On June 30, 2011, five individuals intervened in the lawsuit and claimed that they are owed overriding royalties under the same leases claimed by the defendants. The Company contends that the intervenors are not entitled to any overriding royalties because the leases claimed by the defendants and the intervenors have expired. The case is set for trial starting October 3, 2011. The Company believes it has gathered evidence to diminish or completely defeat the defendants’ and the intervenors’ interest ownership claims and will continue to vigorously pursue this claim.

The Company has been expensing legal defense costs on these proceedings as they are incurred. With respect to the Navasota Resources, Tillotson and J. Ken Welch matters, the Company has not accrued a liability for settlement or other resolution of these proceedings because, in the Company’s judgment, the incurrence or amount of such liabilities is either not probable or not reasonably estimable.

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

13. Statement of Cash Flows – Supplemental Information

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

 

		For the Six Months Ended
		June 30,
		2011				2010
		(in thousands)
Cash paid for interest		$	387			$	193
Cash paid for taxes			—				452
Non-cash transactions:
Term deposit surrendered for accrued taxes		$	—			$	70,446
Non-cash capital expenditures excluded from accounts payable and accrued drilling costs			1,359				3,527
Asset retirement obligation included in natural gas and oil properties			178				54
Drilling advances application			204				150

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

 

•

financial position;

 

•

business strategy and budgets;

 

•

anticipated capital expenditures;

 

•

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

 

•

natural gas and oil reserves;

 

•

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

 

•

operating costs and other expenses;

 

•

cash flow and anticipated liquidity;

 

•

prospect development; and

 

•

property acquisitions and sales.

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

 

•

the supply and demand for natural gas and oil;

 

•

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

 

•

natural gas and oil price volatility;

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

strength and financial resources of competitors;

 

•

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

 

•

availability and cost of processing and transportation;

 

•

changes or advances in technology;

 

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•

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

 

•

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

 

•

environmental risks;

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

ability to find and retain skilled personnel; and

 

•

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

For a more detailed description of the risks and uncertainties that we face and other factors that could affect our financial performance or cause our actual results to differ materially from our projected results please see (i) Part II, Item 1A. “Risk Factors” and elsewhere in this report, (ii) Part I, Item 1A. “Risk Factors” and elsewhere in our 2010 Form 10-K, (iii) our subsequent reports and registration statements filed from time to time with the SEC and (iv) other announcements we make from time to time.

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

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

Overview

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

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

Our current operational activities are conducted primarily in the United States. As of June 30, 2011, our major assets consist of approximately 99,500 gross (74,200 net) acres in the Marcellus Shale in West Virginia and southwestern Pennsylvania, approximately 35,200 gross (19,400 net) acres in the Bossier play in the Hilltop area of

 

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East Texas, and approximately 43,400 gross (19,600 net) acres in the Powder River Basin of Wyoming and Montana.

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

Natural Gas and Oil Activities

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

Appalachia – West Virginia and Central and Southwestern Pennsylvania. The Marcellus Shale is Devonian aged shale that underlies much of the Appalachian region of Pennsylvania, New York, Ohio, West Virginia and adjacent states. The depth of the Marcellus Shale and its low permeability make the Marcellus Shale an unconventional exploration target. Advancements in stimulation and horizontal drilling have produced promising results in the Marcellus Shale. These developments have resulted in increased leasing and drilling activity in the area. As of June 30, 2011, our acreage position in the play was approximately 99,500 gross (74,200 net) acres, of which approximately 41,800 gross (19,600 net) acres are referred to as Marcellus West acreage, reflecting our interest after the 50% interest is assigned under the Atinum Joint Venture, and 57,700 gross (54,600 net) acres are referred to as Marcellus East acreage. The entirety of our acreage is believed to be in the core, over-pressured area of the Marcellus play and is in close proximity to wells being drilled by other operators.

In early 2010, we completed the drilling of our first vertical Marcellus Shale well, the Yoho #1. The well tested at a stabilized gross rate of 1.5 MMcf and 120 barrels of condensate per day, with no water production at approximately 1,000 psi of flowing tubing pressure. We are currently waiting for a connection to a pipeline and do not expect natural gas sales until the fourth quarter of 2011.

On September 21, 2010, we entered into the Atinum Joint Venture pursuant to a purchase and sale agreement with Atinum. Pursuant to the agreement, at the closing of the transaction on November 1, 2010, we assigned to Atinum, for $70.0 million in total consideration, an initial 21.43% interest in all of our existing Marcellus Shale assets in West Virginia and Pennsylvania, consisting of certain undeveloped acreage and a 50% working interest in 16 producing shallow conventional wells and one non-producing vertical Marcellus Shale well (the “Atinum Joint Venture Assets”). Atinum paid us approximately $30.0 million in cash upon closing. Additionally, Atinum is obligated to fund its 50% share of drilling, completion and infrastructure costs, and will pay an additional $40.0 million of future drilling costs in the form of a drilling carry obligation by funding 75% of our 50% share of those same costs. Upon completion of the funding of the drilling carry, we will make additional assignments, as necessary, to Atinum as a result of which Atinum will own a 50% interest in the Atinum Joint Venture Assets. As of June 30, 2011, approximately $32.9 million of drilling carry obligation remained outstanding.

The Atinum Joint Venture is pursuing an initial three-year development program that calls for the partners to drill a minimum of 12 horizontal wells in 2011 and 24 horizontal wells in each of 2012 and 2013. Through June 30, 2011, an initial AMI was established for potential additional acreage acquisitions in Ohio and New York along with the counties in West Virginia and Pennsylvania in which the existing Atinum Joint Venture Assets were located. Subsequent to June 30, 2011, Atinum has the right to participate in any future leasehold acquisitions made by us within Ohio, New York, Pennsylvania and West Virginia, excluding the counties of Pendleton, Pocahontas, Preston, Randolph and Tucker, West Virginia, on terms identical to those governing the existing Atinum Joint Venture. We will act as operator and are obligated to offer any future lease acquisitions to Atinum on a 50/50 basis and Atinum will pay us on an annual basis an amount equal to 10% of lease bonuses and third party leasing costs up to $20.0 million and 5% of such costs on activities above $20.0 million.

 

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In December 2010, we completed a Marcellus Shale leasehold acquisition (the “Marcellus East Acquisition”) for an aggregate purchase price of $28.9 million. The acquisition consisted of undeveloped leasehold in the Marcellus Shale concentrated in Preston, Tucker, Pocahontas, Randolph and Pendleton Counties, West Virginia, including a gathering system comprised of 41 miles of four and six inch steel pipeline, a salt water disposal well, and five conventional producing wells. The Marcellus East Acquisition acreage was outside the initial AMI with Atinum, and Atinum elected not to acquire a 50% interest as provided under the terms of the Atinum Joint Venture. We believe their decision was due to the timing of the transaction and limited prior operational results within the initial Atinum Joint Venture AMI. We have completed the drilling of the Hickory Ridge 2H horizontal Marcellus well on the Marcellus East Acquisition acreage in Preston County and anticipate completing the well with multi-stage fracture stimulation in August 2011 with first sales anticipated in September 2011. No additional wells are currently planned to be drilled on the Marcellus East Acquisition acreage in 2011 pending the completion of a 3-D seismic survey over a portion of the Marcellus East Acquisition acreage.

As of June 30, 2011, in Marshall County West Virginia, we had completed drilling of the Wengerd 1H and 7H Marcellus wells with horizontal lateral extensions of approximately 4,700 feet and 5,700 feet, respectively, and were in the process of drilling the Corley 1H Marcellus horizontal well. By early July 2011, we had successfully completed fracing operations on the Wengerd 1H and 7H wells and initial combined daily flow test results were approximately 15.5 MMcf/d of 1,285 Btu natural gas, 1,100 barrels of condensate and more than 150 barrels of frac water per hour at approximately 1,200 psi flow casing pressure per well. We anticipate sales will commence no later than mid-August 2011. After all drilling and completing costs have been incurred, we will have an approximate 44.5% working interest and an approximate 37.5% net revenue interest in the Wengerd wells. Subsequent to June 30, 2011, drilling operations were completed on the Corley 1H and 3H Marcellus horizontal wells each with an average lateral extension of approximately 5,250 feet. Drilling operations are currently in progress on the Corley 2H well to be followed by the drilling of the Corley 4H well with both wells projected to have average lateral extensions of approximately 5,100 feet. Completion operations on the four Corley horizontal wells are anticipated to commence in September 2011 with first sales anticipated in early November 2011. After all drilling and completing costs have been incurred, we will have an approximate 40% working interest and an approximate 34.5% net revenue interest in the Corley wells. As of year end 2011, we anticipate our operated well activity in Marshall County, West Virginia, to be comprised of 9 gross (4 net) wells on sales, 9 gross (3.7 net) wells drilled awaiting completion and 5 gross (2.5 net) top holes drilled. All wells drilled in Marshall County are subject to the Atinum Joint Venture and after all drilling and completing costs have been incurred, our working interest will range from approximately 50% to 40% with a corresponding 43% to 34.5% net revenue interest with average lateral extensions of approximately 5,000 feet.

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

For the three and six months ended June 30, 2011, net production from the Appalachia area averaged approximately 0.6 MMcfe/d, respectively, compared to 0.4 MMcfe/d for the first and second quarters of 2010, respectively.

Hilltop Area, East Texas. The majority of our activities in the first half of 2011 have been in the Bossier and shallower potential oil zones in the Hilltop area of East Texas, approximately midway between Dallas and Houston in Leon and Robertson Counties. As of June 30, 2011, our acreage position in the play was approximately 35,200 gross (19,400 net) acres. Wells in this area target multiple potentially productive natural gas formations and are typically characterized by high initial production and attractive long-lived per well reserves.

In May 2010, we drilled the Wildman 6H, a horizontal well, in the Glen Rose formation and completed it with a single stage fracture stimulation. The Wildman 6H well was completed using a slotted liner which did not allow for the multi-stage fracture stimulation of the horizontal wellbore where several natural fractures were observed. During the second quarter, the well’s average daily production was approximately 10 bbl/d. Recognizing that our original completion approach was not optimal, we decided to further test the Glen Rose formation.

 

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Subsequently, we drilled two other wells to test the Glen Rose formation—another horizontal well, the Wildman 8H, and a vertical well, the Williams #2. The Wildman 8H and Williams #2 were fracture stimulated and completed in late February 2011. During the second quarter, the Wildman 8H average daily production was approximately 100 bbl/d. While initial production results were encouraging, subsequent oil production has been lower than expected, primarily as a result of excessive water production. We will continue to monitor production before continuing with horizontal development of the Glen Rose formation. The Williams #2 was initially flowing naturally after stimulation and was placed on artificial lift at a current rate of approximately 6 bbl/d. In June 2011 we added an additional Glen Rose completion and the well is currently averaging approximately 30 bbl/d on artificial lift. Ultimately we plan on commingling the Glen Rose completions and an Eagle Ford Shale/Woodbine completion in the Williams #2 well in later 2011.

In January 2011, we attempted to test the Eagle Ford Shale/Woodbine formation with one well in East Texas, the Wildman 7H. The Wildman 7H horizontal well was intended to test the Eagle Ford Shale/Woodbine formation, but due to drilling issues, the well was re-targeted and the horizontal lateral drilled in a slightly deeper transitional limestone zone known as the False Buda. The well was fracture stimulated with a 16-stage completion. Micro-seismic information was gathered during the completion process, and processing and interpretation of that data revealed that our fracture stimulation did not extend upward as anticipated in order to allow extraction from the Eagle Ford Shale/Woodbine formation. The Wildman 7H initially flowed at gross 145 bbl/d and was placed on artificial lift in mid-February 2011. Production in the second quarter averaged approximately gross 24 bbl/d. We have postponed drilling a subsequent well in 2011 until we have received final core analysis of the Eagle Ford Shale/Woodbine formation taken during the drilling of the Belin #3 well, the additional production results from the Wildman 7H well and additional information from monitoring of offset operator drilling activity in the zone. If we drill an additional Eagle Ford/Woodbine Shale well, we expect the horizontal lateral will be targeted within the portion of the Eagle Ford Shale/Woodbine formation that was originally the target of the Wildman 7H well.

In December 2010, we began drilling the Belin #2 well, an exploration well testing the deep Bossier formation in a separate fault block near the Belin #1 well. The well reached total depth of 19,650 feet and encountered approximately 130 net feet of pay in the lower Bossier formation within five separate sand intervals. The initial formation zone was fracture stimulated in April 2011 with marginal results and a bridge plug was set. In early May 2011, we fracture stimulated the next zone, which, based on log interpretation, should be the most productive lower Bossier zone in the well. During fracture stimulation of the well, we encountered an equipment failure and the frac operation had to be stopped before the designed frac job was completed. We subsequently attempted to re-frac the zone but we were unsuccessful in surpassing any reservoir damage from the first aborted frac attempt. Production from the well is currently averaging approximately 400 Mcf/d. We plan on plugging the existing zone perforations and re-perforating and re-fracture stimulating the zone in November 2011. We have a 67% before payout working interest and an approximate 50% before payout net revenue interest in the Belin #2 well.

We drilled the Belin #3 well in the same fault block as the Belin #2 well. The well reached total depth of 20,100 feet in mid-July 2011 and encountered approximately 60 net feet of pay in the lower Bossier formation within four separate sand intervals. The lower formation zones are scheduled to be fracture stimulated in September 2011. We have a 67% before payout working interest and an approximate 50% before payout net revenue interest in the Belin #3 well.

In addition to the contemplated fracture stimulation operations on the Belin #2 and #3 wells, we are planning to add two recompletion zones in the Wildman #5 during the fourth quarter. Once the recompletions have been completed and pressures are normalized, we plan to commingle all zones in the well.

For the three and six months ended June 30, 2011, net production from the Hilltop area averaged approximately 16.6 MMcfe/d and 18.5 MMcfe/d, respectively, compared to 13.6 MMcfe/d and 15.3 MMcfe/d for the three and six months ended June 30, 2010, respectively.

Coalbed Methane – Powder River Basin, Wyoming and Montana. As of June 30, 2011, we own an approximate 40% average working interest in approximately 43,400 gross (19,600 net) acres in the Powder River Basin of Wyoming and Montana. As a result of decreased drilling activity, Powder River Basin production averaged 1.4 MMcfe/d for the three and six months ended June 30, 2011, respectively, compared to 1.8 MMcfe/d and 2.0 MMcfe/d for the three and six months ended June 30, 2010, respectively.

 

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Recent Gastar USA Preferred Equity Financing

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

On June 29, 2011, Gastar USA entered into an ATM Agreement with MLV. According to the provisions of the ATM agreement, Gastar USA may offer and sell from time to time up to 3,400,000 shares of Series A Preferred Stock through MLV, as our sales agent. Sales of the units will be made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between Gastar USA and MLV. During the six months ended June 30, 2011, Gastar USA sold 4,433 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $97,000. Subsequent to June 30, 2011 through August 3, 2011, we sold an additional 60,463 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $1.3 million. We plan to continue issuing Series A Preferred Stock under the ATM Agreement in the future depending on our capital expenditures program and market conditions. See “Liquidity and Capital Resources.”

Results of Operations

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

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

 

		For the Three Months Ended								For the Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
Production:
Natural gas (MMcf)			1,634				1,428				3,600				3,181
Oil (MBbl)			11				2				21				4
Total production (MMcfe)			1,697				1,440				3,728				3,204
Total (Mmcfe/d)			18.6				15.8				20.6				17.7
Average sales price per unit:
Natural gas per Mcf, excluding impact of realized hedging activities		$	3.52			$	3.50			$	3.43			$	3.97
Natural gas per Mcf, including impact of realized hedging activities			4.59				4.62				4.60				4.16
Oil per Bbl			96.66				72.67				92.30				72.36
Selected operating expenses (in thousands):
Production taxes		$	118			$	93			$	227			$	216
Lease operating expenses			1,875				1,914				3,582				3,657
Transportation, treating and gathering			1,123				1,094				2,226				2,343
Depreciation, depletion and amortization			2,991				1,664				7,103				3,395
General and administrative expense			2,596				3,944				5,476				7,776
Selected operating expenses per Mcfe:
Production taxes		$	0.07			$	0.06			$	0.06			$	0.07
Lease operating expenses			1.10				1.33				0.96				1.14
Transportation, treating and gathering			0.66				0.76				0.60				0.73
Depreciation, depletion and amortization			1.76				1.16				1.91				1.06
General and administrative expense			1.53				2.74				1.47				2.43

 

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

Revenues. Substantially all of our revenues are derived from the production of natural gas in the United States. Natural gas and oil revenues were $8.5 million for the three months ended June 30, 2011, up from $6.7 million for the three months ended June 30, 2010. The increase in revenues was the result of a 7% increase in prices and an 18% increase in volumes. Average daily production on an equivalent basis was 18.6 MMcfe/d for the three months ended June 30, 2011 compared to 15.8 MMcfe/d for the same period in 2010.

During the three months ended June 30, 2011, approximately 79% of our natural gas production was hedged. The realized effect of hedging on natural gas sales was an increase of $1.7 million in natural gas and oil revenues resulting in an increase in total price realized from $3.52 per Mcf to $4.59 per Mcf. The realized hedge impact includes a benefit of $429,000 for amortization of prepaid call sale premiums. Excluding the non-cash amortization, the realized effect of hedging was an increase in revenues of $1.3 million, which was comprised of $2.3 million of NYMEX hedge gains offset by $248,000 of regional basis losses and payment of deferred put premiums of $686,000. For the remainder of 2011, we have costless three way collar hedges for approximately 3,300 MMBtu/d with a weighted average floor of $6.00, short put of $4.00 and a ceiling of $7.00. In addition, we have put spread hedges for approximately 14,300 MMBtu/d with a weighted average floor of $6.07 and a short put of $4.14. Currently, these hedge positions represent approximately 75% of our estimated future 2011 natural gas production. During the three months ended June 30, 2010, the realized effect of hedging on natural gas sales was an increase of $1.6 million in natural gas and oil revenues resulting in an increase in total price realized from $3.50 per Mcf to $4.62 per Mcf. The 2010 realized hedge impact included $724,000 of amortization of prepaid put purchase premiums.

Unrealized natural gas hedge gain was $502,000 for the three months ended June 30, 2011 compared to an unrealized natural gas hedge loss of $972,000 for the three months ended June 30, 2010. The decrease in unrealized natural gas hedge loss is the result of lower future NYMEX gas prices partially offset by losses related to projected basis differentials.

Production taxes. We reported production taxes of $118,000 for the three months ended June 30, 2011 compared to $93,000 for the three months ended June 30, 2010. The increase in production taxes primarily resulted from higher oil taxes due to increased oil production in Texas, partially offset by lower revenues in Wyoming due to lower production volumes and gas prices.

Lease operating expenses. We reported lease operating expenses of $1.9 million for the three months ended June 30, 2011 and June 30, 2010, respectively. Our lease operating expenses were $1.10 per Mcfe for the three months ended June 30, 2011 compared to $1.33 per Mcfe for the same period in 2010. The decrease in the rate per Mcfe was primarily due to lower ad valorem taxes of $0.09 per Mcfe and lower workover costs of $0.22 per Mcfe as well as higher production volumes during the three months ended June 30, 2011.

Transportation, treating and gathering. We reported transportation expenses of $1.1 million for the three months ended June 30, 2011 and June 30, 2010, respectively. The current quarter included $411,000 of charges under our Hilltop gas gathering agreement with Hilltop Resort GS, LLC compared to $543,000 of such charges in the same quarter of 2010. Such charges resulted from actual production volumes being less than minimum contractual volume requirements.

Depreciation, depletion and amortization. We reported depreciation, depletion and amortization (“DD&A”) expense of $3.0 million for the three months ended June 30, 2011 up from $1.7 million for the three months ended June 30, 2010. The increase in DD&A expense was the result of a 52% increase in the DD&A rate per Mcfe and an 18% increase in production. The DD&A rate for the three months ended June 30, 2011 was $1.76 per Mcfe compared to $1.16 per Mcfe for the same period in 2010. The increase in the rate is primarily due to higher proved costs associated with recent East Texas wells drilled to test oil prospects with limited initial reserve increases from these activities. Additionally, the June 30, 2010 DD&A rate was reduced by the gathering system sales proceeds credited to proved property costs in the fourth quarter of 2009.

General and administrative. We reported general and administrative expenses of $2.6 million for the three months ended June 30, 2011, down from $3.9 million for the three months ended June 30, 2010. Non-cash stock-

 

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based compensation expense, which is included in general and administrative expense, was $538,000 and $880,000 for the three months ended June 30, 2011 and 2010, respectively. The decrease in stock-based compensation expense is primarily due to the forfeiture of previously issued unvested awards as a result of employee resignations, prior year awards being fully amortized and recently issued shares having a lower fair value. Excluding stock-based compensation expense, general and administrative expense decreased $1.0 million to $2.1 million for the three months ended June 30, 2011 compared to June 30, 2010. This decrease is primarily due to lower legal fees as a result of the Classic Star litigation settlement in November 2010.

Investment income and other. We reported investment income of $3,000 for the three months ended June 30, 2011 compared to $548,000 for the three months ended June 30, 2010. The decrease in investment income is primarily due to including, in the three months ended June 30, 2010, interest earned on the Australian term deposit established in conjunction with the sale of the Australian properties in July 2009 for the future tax payment on the sale. At maturity on June 1, 2010, the term deposit was used to settle the Australian tax liability resulting from the Australian property sale in 2009 and thus resulting in no comparable investment income for the three months ended June 30, 2011.

Warrant derivative gain (loss). For the three months ended June 30, 2010, we reported a $55,000 unrealized gain related to the fair value measurement of our warrants outstanding. At June 30, 2011 the outstanding warrants had a zero fair market value.

Provision for income tax expense (benefit). We did not report an income tax benefit or expense for the three months ended June 30, 2011. For the three months ended June 30, 2010, we reported income tax expense of $57,000. The 2010 tax expense was primarily due to withholding tax on the interest income from the Australian term deposit. At maturity on June 1, 2010, the term deposit was used to settle the tax liability resulting from the Australian property sale in 2009.

Six Months Ended June 30, 2011 compared to the Six Months Ended June 30, 2010

Revenues. Natural gas and oil revenues were $18.5 million for the six months ended June 30, 2011, up from $13.5 million for the six months ended June 30, 2010. The increase in revenues was the result of an 18% increase in prices and a 16% increase in volumes. Average daily production on an equivalent basis was 20.6 MMcfe/d for the six months ended June 30, 2011 compared to 17.7 MMcfe/d for the same period in 2010.

During the six months ended June 30, 2011, approximately 84% of our natural gas production was hedged. The realized effect of hedging on natural gas sales was an increase of $4.2 million in natural gas and oil revenues resulting in an increase in total price realized from $3.43 per Mcf to $4.60 per Mcf. The realized hedge impact includes a benefit of $871,000 for amortization of prepaid call sale premiums. Excluding the non-cash amortization, the realized effect of hedging was an increase in revenues of $3.4 million, which was comprised of $5.2 million of NYMEX hedge gains offset by $484,000 of regional basis losses and payment of deferred put premiums of $1.4 million. During the six months ended June 30, 2010, the realized effect of hedging on natural gas sales was an increase of $594,000 in natural gas and oil revenues resulting in an increase in total price realized from $3.97 per Mcf to $4.16 per Mcf. The 2010 realized hedge impact included $1.8 million of amortization of prepaid put purchase premiums.

Unrealized natural gas hedge loss was $1.4 million for the six months ended June 30, 2011 compared to unrealized natural gas hedge income of $8.4 million for the six months ended June 30, 2010. The loss for the six months ended June 30, 2011 is primarily due to a decrease in future volumes hedged and change in actual future hedged prices compared to the future price curve.

Production taxes. We reported production taxes of $227,000 for the six months ended June 30, 2011 compared to $216,000 for the six months ended June 30, 2010. The increase in production taxes primarily resulted from higher oil taxes due to increased oil production in Texas and higher taxes in West Virginia due to additional production, partially offset by lower revenues in Wyoming due to lower production volumes and gas prices.

Lease operating expenses. We reported lease operating expenses of $3.6 million for the six months ended June 30, 2011 compared to $3.7 million for the six months ended June 30, 2010. Our lease operating expenses were

 

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$0.96 per Mcfe for the six months ended June 30, 2011 compared to $1.14 per Mcfe for the same period in 2010. The decrease in the rate per Mcfe was primarily due to lower ad valorem taxes of $0.09 per Mcfe and lower workover costs of $0.14 per Mcfe as well as higher production volumes during the six months ended June 30, 2011.

Transportation, treating and gathering. We reported transportation expenses of $2.2 million for the six months ended June 30, 2011, down slightly from $2.3 million for the six months ended June 30, 2010. The current year to date period includes $678,000 of charges under our Hilltop gas gathering agreement with Hilltop Resort GS, LLC compared to $934,000 of such charges for the same period in 2010. Such charges resulted from actual production volumes being less than minimum contractual volume requirements.

Depreciation, depletion and amortization. We reported DD&A expense of $7.1 million for the six months ended June 30, 2011 up from $3.4 million for the six months ended June 30, 2010. The increase in DD&A expense was the result of an 80% increase in the DD&A rate per Mcfe and a 16% increase in production. The DD&A rate for the six months ended June 30, 2011 was $1.91 per Mcfe compared to $1.06 per Mcfe for the same period in 2010. The increase in the rate is primarily due to higher proved costs associated with recent East Texas wells drilled to test oil prospects with limited initial reserve increases from these activities. The proved cost increase in the first half of 2011 also included re-classes of undeveloped costs including capitalized interest primarily related to wells in Texas. The June 30, 2010 DD&A rate was partially benefitted by the gathering system sales proceeds credited to proved property costs in the fourth quarter of 2009.

General and administrative. We reported general and administrative expenses of $5.5 million for the six months ended June 30, 2011, down from $7.8 million for the six months ended June 30, 2010. Non-cash stock-based compensation expense, which is included in general and administrative expense, was $1.2 million and $1.6 million for the six months ended June 30, 2011 and 2010, respectively. The decrease in stock-based compensation expense is primarily due to the forfeiture of previously issued unvested awards as a result of director and employee resignations, prior year awards being fully amortized and recently issued shares having a lower fair value. Excluding stock-based compensation expense, general and administrative expense decreased $1.9 million to $4.2 million for the six months ended June 30, 2011 compared to June 30, 2010. This decrease is primarily due to lower legal fees as a result of the Classic Star litigation settlement in November 2010.

Interest expense. We reported interest expense of $63,000 for the six months ended June 30, 2011 compared to $98,000 for the six months ended June 30, 2010. The decrease in interest expense primarily resulted from the payoff of the short-term loan in January 2010.

Investment income and other. We reported investment income of $5,000 for the six months ended June 30, 2011 compared to $1.3 million for the six months ended June 30, 2010. The decrease in investment income is primarily due to including, in the six months ended June 30, 2010, interest earned on the Australian term deposit established in conjunction with the sale of the Australian properties in July 2009 for the future tax payment on the sale. At maturity on June 1, 2010, the term deposit was used to settle the Australian tax liability resulting from the Australian property sale in 2009 and thus resulting in no comparable investment income for the six months ended June 30, 2011.

Warrant derivative gain (loss). For the six months ended June 30, 2010, we reported a $203,000 unrealized gain related to the fair value measurement of our warrants outstanding. At June 30, 2011, the outstanding warrants had a zero fair market value.

Foreign transaction gain. We reported a foreign transaction gain of $3,000 for the six months ended June 30, 2011 compared to a gain of $335,000 for the six months ended June 30, 2010. The decrease in the foreign transaction gain is primarily due to the decrease in Australian denominated cash and accounts receivable balances arising from the sale of the Australian properties in 2009.

Provision for income tax expense (benefit). We did not report an income tax benefit or expense for the six months ended June 30, 2011. For the six months ended June 30, 2010, we reported an income tax benefit of $792,000. The 2010 income tax benefit was primarily due to a $1.0 million downward adjustment of the tax expense related to the sale of the Australian properties after final review from the Australian Tax Office partially

 

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offset by withholding tax on the interest income from the Australian term deposit. At maturity on June 1, 2010, the term deposit was used to settle the tax liability resulting from the Australian property sale in 2009.

Liquidity and Capital Resources

Overview. Our primary sources of liquidity and capital resources are internally generated cash flows from operating activities or asset sales, availability under the Revolving Credit Facility, and access to capital markets, to the extent available. In addition, our Atinum Joint Venture will provide a cash source for our Marcellus Shale development program by providing carried interest funding of up to $40.0 million, of which $32.9 million remained available to fund our share of future drilling and completion costs on joint venture wells at June 30, 2011. We continually evaluate our capital needs and compare them to our capital resources and ability to raise funds in the financial markets. We adjust capital expenditures in response to changes in natural gas and oil prices, drilling results and cash flow.

For the six months ended June 30, 2011, we reported cash flows provided by operating activities of $7.7 million, net cash used in investing activities, primarily for the development and purchase of natural gas and oil properties, of $31.5 million and net cash provided by financing activities of $21.8 million, consisting of $14.0 million of proceeds from issuances of 650,728 shares of Gastar USA’s Series A Preferred Stock and $8.0 million of net borrowings under our Revolving Credit Facility. As a result of these activities, our cash and cash equivalents balance decreased by $1.9 million, resulting in a cash and cash equivalents balance of $5.5 million at June 30, 2011.

At June 30, 2011, we had a net working capital deficit of approximately $16.9 million, including $11.8 million of advances from non-operators, a portion of which will be applied to our net future costs pursuant to the carried interest provisions of the Atinum Joint Venture. At June 30, 2011, availability under our Revolving Credit Facility was $42.0 million.

Future capital and other expenditure requirements. Capital expenditures for the remainder of 2011 are projected to be approximately $37.3 million, consisting of drilling, completion, infrastructure, lease acquisition and seismic costs of $30.5 million in Appalachia and $5.2 million in East Texas and an additional $1.6 million for capitalized interest and other costs. We plan on funding this capital activity through existing cash balances, internally generated cash flow from operating activities, borrowings under the Revolving Credit Facility, a possible joint venture for the development of our Marcellus Acquisition acreage and possible future at-the-market issuances of Series A Preferred Stock by Gastar USA. The majority of projected capital expenditures are operated by us and thus, we can adjust capital expenditures for changes in commodity prices, cash flows from operating activities, availability under the Revolving Credit Facility or issuances of Gastar USA preferred equity. Our capital expenditures and the scope of our drilling activities may change as a result of several factors, including, but not limited to, changes in natural gas and oil prices, costs of drilling and completion and leasehold acquisitions and drilling results.

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

To mitigate some of the potential negative impact on cash flows caused by changes in natural gas prices, we have entered into financial commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge natural gas price risk. In addition to NYMEX swaps and collars and fixed price swaps, we also have entered into basis only swaps. With a basis only swap, we have hedged the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location. See Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report.

At June 30, 2011, the estimated fair value of all of our commodity derivative instruments was a net asset of $13.3 million, comprised of current and noncurrent assets and liabilities. In conjunction with certain commodity derivative hedging activity, we deferred the payment of certain put premiums for the production month period July 2010 through December 2012. At June 30, 2011, we had a current commodity derivative premium payable of $4.1

 

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million and a long-term commodity derivative premium payable of $2.6 million. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month.

By removing the price volatility from a portion of our natural gas for 2011, 2012 and 2013, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flows for those periods. While mitigating negative effects of falling commodity prices, certain derivative contracts also limit the benefits we could receive from increases in commodity prices.

As of June 30, 2011, all of our economic derivative hedge positions were with a multinational energy company or large financial institutions, which are not known to us to be in default on their derivative positions. Credit support for our open derivatives at June 30, 2011 is provided under the Revolving Credit Facility through inter-creditor agreements or open credit accounts of up to $5.0 million. We are exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, we do not anticipate non-performance by such counterparties.

Revolving Credit Facility. At June 30, 2011, we had $8.0 million outstanding under the Revolving Credit Facility compared to our December 31, 2010 outstanding balance of zero. The increase in our long-term debt balance is associated with expenditures for the development of natural gas and oil properties during the six months ended June 30, 2011 of $39.1 million. On June 6, 2011, our borrowing base was increased to $50.0 million, an increase of $2.5 million from the prior borrowing base limit. Borrowing base redeterminations are scheduled semi-annually with the next redetermination scheduled for November 2011.

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

Borrowings under the Revolving Credit Facility bear interest, at our election, at the prime rate or LIBO rate plus an applicable margin. Pursuant to the Revolving Credit Facility, the applicable interest rate margin varies from 1.0% to 2.0% in the case of borrowings based on the prime rate and from 2.5% to 3.5% in the case of borrowings based on the LIBO rate, depending on the utilization percentage in relation to the borrowing base. Under the Revolving Credit Facility, we are subject to certain financial covenants, including interest coverage ratio, a total net indebtedness to EBITDA ratio and current ratio requirement. At August 3, 2011, our availability under our Revolving Credit Facility was $37.0 million.

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

Off-Balance Sheet Arrangements

As of June 30, 2011, we had no off-balance sheet arrangements. We have no plans to enter into any off- balance sheet arrangements in the foreseeable future.

Commitments and Contingencies

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

We are party to various litigation matters and administrative claims arising out of the normal course of business. Although the ultimate outcome of each of these matters cannot be absolutely determined and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters, management does not believe any such

 

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matters will have a material adverse effect on our financial position, results of operations or cash flows. A discussion of current legal proceedings is set forth in Part. I Item 1. “Financial Statements, Note 12 – Commitments and Contingencies” of this report.

Critical Accounting Policies and Estimates

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

 

•

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

 

•

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

Significant accounting policies that we employ and information about the nature of our most critical accounting estimates, our assumptions or approach used and the effects of hypothetical changes in the material assumptions used to develop each estimate are presented in Part I, Item I. “Financial Statements, Note 2 -Summary of Significant Accounting Policies” of this report and in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates” included in our 2010 Form 10-K.

Recent Accounting Developments

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our major commodity price risk exposure is to the prices received for our natural gas production. Our results of operations and operating cash flows are affected by changes in market prices. Realized commodity prices received for our production are the spot prices applicable to natural gas in the region produced. Prices received for natural gas are volatile and unpredictable and are beyond our control. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. For the three and six months ended June 30, 2011, a 10% change in the prices received for natural gas production would have had an approximate $677,000 and $1.4 million impact, respectively, on our revenues prior to hedge transactions to mitigate our commodity pricing risk. See Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report for additional information regarding our hedging activities.

Interest Rate Risk

At June 30, 2011, we had $8.0 million outstanding under the Revolving Credit Facility. Based on the amount outstanding under our Revolving Credit Facility at June 30, 2011, a one percentage point change in the interest rate would have had a $20,000 impact on our interest expense, all of which would have been capitalized. We currently do not use interest rate derivatives to mitigate our exposure to the volatility in interest rates, including under the Revolving Credit Facility, as this risk is minimal.

Foreign Currency Exchange Risk

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

 

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Item 4. Controls and Procedures

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

Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of Parent and the President and Treasurer of Gastar USA, Parent and Gastar USA each conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (“Exchange Act”), as of June 30, 2011. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of Parent and the President and Treasurer of Gastar USA concluded that, as of June 30, 2011, each company’s disclosure controls and procedures were effective in providing reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer of Parent and the President and Treasurer of Gastar USA, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended June 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations such as shales. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the U.S. Environmental Protection Agency (the “EPA”) recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program, and has begun the process of drafting guidance documents on regulating requirements for companies that plan to conduct hydraulic fracturing using diesel. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a number of federal agencies are analyzing a number of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing activities, with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy and the U.S. Government Accountability Office are studying different aspects of how hydraulic fracturing might adversely affect the environment, and the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal land, which, if adopted, would affect our operations on federal lands. A committee of the United States House of Representatives also has conducted an investigation of hydraulic fracturing practices. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the Safe Drinking Water Act or under newly established legislation. In addition, for the second consecutive session, Congress is considering two companion bills, known as the “Fracturing Responsibility and Awareness of Chemicals Act,” or “FRAC Act,” that would repeal an exemption in the Safe Drinking Water Act for the underground injection of hydraulic fracturing fluids other than diesel near drinking water sources. This legislation, if adopted, would require federal regulation of hydraulic fracturing as well as disclosure of the chemicals used in the fracturing process.

Also, some states, including New York, Pennsylvania, Texas and Wyoming, have adopted, and other states are considering adopting, regulations imposing disclosure obligations or restrictions on hydraulic fracturing activities in certain circumstances. New York has imposed a de facto moratorium on the issuance of permits for high-volume, horizontal hydraulic fracturing until state-administered environmental studies are finalized, a preliminary revised draft of which was issued in July 2011, with a more complete revised draft expected to be issued for public comment in August 2011. Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed and Wyoming has adopted legislation requiring drilling operators conducting hydraulic fracturing activities in that state to publicly disclose the chemicals used in the fracturing process. More recently, in June 2011, Texas adopted a law that requires written disclosure to the Railroad Commission of Texas, or “RCT,” and the public of specific information about the fluids, proppants and additives used in hydraulic fracturing treatment operations. Hydraulic fracturing is a primary production method used by us to produce reserves located in the Marcellus Shale formations and East Texas area. If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could make it more difficult or costly for us to perform hydraulic fracturing or otherwise reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. In addition, if hydraulic fracturing is regulated at the federal level, exploration and production activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements and attendant permitting delays and potential

 

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increases in costs. Some or all of these developments could have a material adverse effect on our business, financial condition and results of operations.

Recently proposed rules regulating air emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs, which may be significant.

On July 28, 2011, the U.S. Environmental Protection Agency (“EPA”) proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards (“NSPS”) to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”), and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and adversely impact our business.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. (Removed and Reserved)

Item 5. Other Information

None.

Item 6.

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

 

Exhibit Number		Description
3.1		Amended and Restated Articles of Incorporation of Gastar Exploration Ltd. (incorporated herein by reference to Exhibit 3.1 the Company’s Amendment No. 1 to Registration Statement on Form S-1/A filed October 13, 2005, Registration No. 333-127498).
3.2		Amended Bylaws of Gastar Exploration Ltd. dated as of June 3, 2010 (incorporated herein by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated June 4, 2010. File No. 001-32714).
3.3		Articles of Amendment and Share Structure attached to and forming part of the Amended and Restated Articles of Incorporation of Gastar Exploration Ltd, dated as of June 30, 2009. (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated July 1, 2009. File No. 001-32714).
3.4		Articles of Amendment attached to and forming part of the Amended and Restated Articles of Incorporation of Gastar Exploration Ltd, dated as of July 23, 2009 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated July 24, 2009. File No. 001-32714).
3.5		Certificate of Incorporation of Gastar Exploration USA, Inc. (incorporated by reference to Exhibit 3.3 to Gastar Exploration USA, Inc.’s Registration Statement on Form S-3, dated May 27, 2011. Registration No. 333-174552).
3.6		Amended and Restated Bylaws of Gastar Exploration USA, Inc. (incorporated by reference to Exhibit 3.3 to Gastar Exploration USA, Inc.’s Registration Statement on Form S-3, dated May 27, 2011. Registration No. 333-174552).
3.7		Certificate of Designation of Rights and Preferences of 8.625% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.3 of Gastar Exploration USA, Inc.’s Form 8A filed on June 20, 2011).
4.1		Indenture related to the 12 3/4% Senior Secured Notes due November 29, 2012, dated as of November 29, 2007, between Gastar Exploration USA, Inc., Gastar Exploration Ltd., Wells Fargo Bank, National Association, as Trustee and Collateral Agent and each of the other Guarantors party thereto (including the form of 12 3/4% Senior Secured Note due 2012) 2007 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated December 4, 2007. File No. 333-32714).

 

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Exhibit Number		Description
4.2		Supplemental Indenture dated as of February 16, 2009, related to the 12 3/4% Senior Secured Notes due 2012, between Gastar Exploration USA, Inc., Gastar Exploration Ltd., Wells Fargo Bank, National Association, as Trustee and Collateral Agent, and each of the other Guarantors party thereto. 2007 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated February 20, 2009. File No. 001-32714).
4.3		Agreement between Gastar Exploration Ltd. and GeoStar Corporation dated August 11, 2005 (incorporated by reference to Exhibit 4.17 of the Company’s Amendment No. 1 to Registration Statement on Form S-1/A, filed on October 30, 2005. Registration No. 333-127498).
4.4		Facsimile of common share certificate of Gastar Exploration Ltd. (incorporated by reference to Exhibit 4.21 of the Company’s Amendment No. 3 to Registration Statement on Form S-1/A, dated December 15, 2005. Registration No. 333-127498).
4.5		Warrant dated June 11, 2008, entitling GeoStar Corporation to acquire, subject to adjustments, 10,000,000 Gastar Exploration Ltd. common shares (incorporated by reference to Exhibit 4.1 of the Company’s Current Report of Form 8-K dated June 13, 2008. File No. 001-32714).
10.1		Guarantee Agreement, dated June 23, 2011, by and between Gastar Exploration Ltd. and Gastar Exploration USA, Inc. (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated June 23, 2011).
10.2		Third Amendment to Amended and Restated Credit Agreement, dated June 14, 2011, by and among Gastar Exploration USA, Inc., the Guarantors party thereto, the Lenders party thereto and Amegy Bank National Association, as Administrative Agent (incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K dated June 15, 2011).
31.1†		Certification of Periodic Financial Reports by Chief Executive Officer of Gastar Exploration Ltd. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
31.2†		Certification of Periodic Financial Reports by Chief Financial Officer of Gastar Exploration Ltd. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
31.3†		Certification of Periodic Financial Reports by President of Gastar Exploration USA, Inc. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
31.4†		Certification of Periodic Financial Reports by Treasurer of Gastar Exploration USA, Inc. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
32.1††		Certification of Periodic Financial Reports by Chief Executive Officer of Gastar Exploration Ltd. in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
32.2††		Certification of Periodic Financial Reports by Chief Financial Officer of Gastar Exploration Ltd. in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
32.3††		Certification of Periodic Financial Reports by President of Gastar Exploration USA, Inc. in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
32.4††		Certification of Periodic Financial Reports by Treasurer of Gastar Exploration USA, Inc. in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
101. INS††		XBRL Instance Document
101. SCH††		XBRL Taxonomy Extension Schema Document
101. CAL††		XBRL Taxonomy Extension Calculation Linkbase Document
101. DEF††		XBRL Taxonomy Extension Definition Linkbase Document
101. LAB††		XBRL Taxonomy Extension Label Linkbase Document
101. PRE††		XBRL Taxonomy Extension Presentation Linkbase Document

 

†	Filed herewith.

††	Furnished herewith.

 

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SIGNATURES

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

 

		GASTAR EXPLORATION LTD.
Date: August 8, 2011		By:		/s/    J. RUSSELL PORTER
				J. Russell Porter
				President and Chief Executive Officer
				(Duly authorized officer and principal executive officer)
Date: August 8, 2011		By:		/s/    MICHAEL A. GERLICH
				Michael A. Gerlich
				Vice President and Chief Financial Officer
				(Duly authorized officer and principal financial and accounting officer)

 

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SIGNATURES

 

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

 

		GASTAR EXPLORATION USA, INC.
Date: August 8, 2011		By:		/s/    J. RUSSELL PORTER
				J. Russell Porter
				President
				(Duly authorized officer and principal executive officer)
Date: August 8, 2011		By:		/s/    MICHAEL A. GERLICH
				Michael A. Gerlich
				Secretary and Treasurer
				(Duly authorized officer and principal financial and accounting officer)

 

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EXHIBIT INDEX

 

Exhibit Number		Description
3.1		Amended and Restated Articles of Incorporation of Gastar Exploration Ltd. (incorporated herein by reference to Exhibit 3.1 the Company’s Amendment No. 1 to Registration Statement on Form S-1/A filed October 13, 2005, Registration No. 333-127498).
3.2		Amended Bylaws of Gastar Exploration Ltd. dated as of June 3, 2010 (incorporated herein by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated June 4, 2010. File No. 001-32714).
3.3		Articles of Amendment and Share Structure attached to and forming part of the Amended and Restated Articles of Incorporation of Gastar Exploration Ltd, dated as of June 30, 2009. (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated July 1, 2009. File No. 001-32714).
3.4		Articles of Amendment attached to and forming part of the Amended and Restated Articles of Incorporation of Gastar Exploration Ltd, dated as of July 23, 2009 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated July 24, 2009. File No. 001-32714).
3.5		Certificate of Incorporation of Gastar Exploration USA, Inc. (incorporated by reference to Exhibit 3.3 to Gastar Exploration USA, Inc.’s Registration Statement on Form S-3, dated May 27, 2011. Registration No. 333-174552).
3.6		Amended and Restated Bylaws of Gastar Exploration USA, Inc. (incorporated by reference to Exhibit 3.3 to Gastar Exploration USA, Inc.’s Registration Statement on Form S-3, dated May 27, 2011. Registration No. 333-174552).
3.7		Certificate of Designation of Rights and Preferences of 8.625% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.3 of Gastar Exploration USA, Inc.’s Form 8A filed on June 20, 2011).
4.1		Indenture related to the 12 3/4% Senior Secured Notes due November 29, 2012, dated as of November 29, 2007, between Gastar Exploration USA, Inc., Gastar Exploration Ltd., Wells Fargo Bank, National Association, as Trustee and Collateral Agent and each of the other Guarantors party thereto (including the form of 12 3/4% Senior Secured Note due 2012) 2007 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated December 4, 2007. File No. 333-32714).
4.2		Supplemental Indenture dated as of February 16, 2009, related to the 12 3/4% Senior Secured Notes due 2012, between Gastar Exploration USA, Inc., Gastar Exploration Ltd., Wells Fargo Bank, National Association, as Trustee and Collateral Agent, and each of the other Guarantors party thereto. 2007 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated February 20, 2009. File No. 001-32714).
4.3		Agreement between Gastar Exploration Ltd. and GeoStar Corporation dated August 11, 2005 (incorporated by reference to Exhibit 4.17 of the Company’s Amendment No. 1 to Registration Statement on Form S-1/A, filed on October 30, 2005. Registration No. 333-127498).
4.4		Facsimile of common share certificate of Gastar Exploration Ltd. (incorporated by reference to Exhibit 4.21 of the Company’s Amendment No. 3 to Registration Statement on Form S-1/A, dated December 15, 2005. Registration No. 333-127498).
4.5		Warrant dated June 11, 2008, entitling GeoStar Corporation to acquire, subject to adjustments, 10,000,000 Gastar Exploration Ltd. common shares (incorporated by reference to Exhibit 4.1 of the Company’s Current Report of Form 8-K dated June 13, 2008. File No. 001-32714).
10.1		Guarantee Agreement, dated June 23, 2011, by and between Gastar Exploration Ltd. and Gastar Exploration USA, Inc. (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated June 23, 2011).

 

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Exhibit Number		Description
10.2		Third Amendment to Amended and Restated Credit Agreement, dated June 14, 2011, by and among Gastar Exploration USA, Inc., the Guarantors party thereto, the Lenders party thereto and Amegy Bank National Association, as Administrative Agent (incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K dated June 15, 2011).
31.1†		Certification of Periodic Financial Reports by Chief Executive Officer of Gastar Exploration Ltd. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
31.2†		Certification of Periodic Financial Reports by Chief Financial Officer of Gastar Exploration Ltd. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
31.3†		Certification of Periodic Financial Reports by President of Gastar Exploration USA, Inc. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
31.4†		Certification of Periodic Financial Reports by Treasurer of Gastar Exploration USA, Inc. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
32.1††		Certification of Periodic Financial Reports by Chief Executive Officer of Gastar Exploration Ltd. in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
32.2††		Certification of Periodic Financial Reports by Chief Financial Officer of Gastar Exploration Ltd. in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
32.3††		Certification of Periodic Financial Reports by President of Gastar Exploration USA, Inc. in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
32.4††		Certification of Periodic Financial Reports by Treasurer of Gastar Exploration USA, Inc. in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
101. INS††		XBRL Instance Document
101. SCH††		XBRL Taxonomy Extension Schema Document
101. CAL††		XBRL Taxonomy Extension Calculation Linkbase Document
101. DEF††		XBRL Taxonomy Extension Definition Linkbase Document
101. LAB††		XBRL Taxonomy Extension Label Linkbase Document
101. PRE††		XBRL Taxonomy Extension Presentation Linkbase Document

 

†	Filed herewith.

††	Furnished herewith.

 

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