Gastar Exploration (GSTCQ) 10-Q 2013 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________________________________________

FORM 10-Q

____________________________________________________

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

FOR THE QUARTERLY PERIOD ENDED March 31, 2013

OR

o 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

Commission File Number: 001-35211

____________________________________________________

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
(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.   

Gastar Exploration Ltd.	Yes	ý	No	o
Gastar Exploration USA, Inc.	Yes	ý	No	o

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).    

Gastar Exploration Ltd.	Yes	ý	No	o
Gastar Exploration USA, Inc.	Yes	ý	No	o

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.

Gastar Exploration Ltd.

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

Gastar Exploration USA, Inc.

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    

Gastar Exploration Ltd.	Yes	o	No	ý
Gastar Exploration USA, Inc.	Yes	o	No	ý

The total number of outstanding common shares, no par value per share, as of April 30, 2013 was

Gastar Exploration Ltd.	68,375,282	shares of common stock
Gastar Exploration USA, Inc.	750	shares of common stock

GASTAR EXPLORATION LTD. AND

GASTAR EXPLORATION USA, INC.

QUARTERLY REPORT ON FORM 10-Q

FOR THE THREE MONTHS ENDED MARCH 31,2013

TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements	4
	Gastar Exploration Ltd. Condensed Consolidated Balance Sheets as of March 31, 2013 (unaudited) and December 31, 2012	4
	Gastar Exploration Ltd. Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2013 and 2012 (unaudited)	5
	Gastar Exploration Ltd. Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012 (unaudited)	6
	Gastar Exploration USA, Inc. Condensed Consolidated Balance Sheets as of March 31, 2013 (unaudited) and December 31, 2012	7
	Gastar Exploration USA, Inc. Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2013 and 2012 (unaudited)	8
	Gastar Exploration USA, Inc. Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012 (unaudited)	9
	Notes to the Condensed Consolidated Financial Statements (unaudited)	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 4.	Controls and Procedures	36
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3.	Defaults Upon Senior Securities	38
Item 4.	Mine Safety Disclosure	38
Item 5.	Other Information	38
Item 6.	Exhibits	39
SIGNATURES		41

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 U.S. dollars unless otherwise noted and (v) all financial data included in this report on Form 10-Q 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 U.S. filings.

2

Glossary of Terms

AMI	Area of Mutual Interest, an agreed designated geographic area where joint venturers or other industry partners have a right of participation in acquisitions and operations
Bbl	Barrel of oil, condensate or NGLs
Bbl/d	Barrels of oil, condensate or NGLs per day
BOE/d	Barrels of oil equivalent per day
Btu	British thermal unit, typically used in measuring natural gas energy content
CRP	Central receipt point
FASB	Financial Accounting Standards Board
MBbl	One thousand barrels of oil, condensate or NGLs
MBbl/d	One thousand barrels of oil, condensate or NGLs per day
Mcf	One thousand cubic feet of natural gas
Mcf/d	One thousand cubic feet of natural gas per day
Mcfe	One thousand cubic feet of natural gas equivalent
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
MMcfe	One million cubic feet of natural gas equivalent
MMcfe/d	One million cubic feet of natural gas equivalent per day
NGLs	Natural gas liquids
NYMEX	New York Mercantile Exchange
psi	Pounds per square inch

3

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2013			December 31, 2012
	(Unaudited)
	(in thousands, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	7,135		$	8,901
Accounts receivable, net of allowance for doubtful accounts of $542 and $546, respectively	8,289			9,540
Commodity derivative contracts	1,217			7,799
Prepaid expenses	991			1,097
Total current assets	17,632			27,337
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, excluded from amortization	74,865			67,892
Proved properties	699,408			671,193
Total natural gas and oil properties	774,273			739,085
Furniture and equipment	1,944			1,925
Total property, plant and equipment	776,217			741,010
Accumulated depreciation, depletion and amortization	(490,124		)	(484,759		)
Total property, plant and equipment, net	286,093			256,251
OTHER ASSETS:
Commodity derivative contracts	854			1,369
Deferred charges, net	825			836
Advances to operators and other assets	2,153			4,275
Deposit for purchase of natural gas and oil properties	7,425			—
Total other assets	11,257			6,480
TOTAL ASSETS	$	314,982		$	290,068
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	18,239		$	23,863
Revenue payable	7,563			8,801
Accrued interest	172			151
Accrued drilling and operating costs	2,888			3,907
Advances from non-operators	33,630			17,540
Commodity derivative contracts	3,491			1,399
Accrued litigation settlement liability	1,000			—
Asset retirement obligation	358			358
Other accrued liabilities	1,707			1,493
Total current liabilities	69,048			57,512
LONG-TERM LIABILITIES:
Long-term debt	115,000			98,000
Commodity derivative contracts	1,725			1,304
Asset retirement obligation	6,445			6,605
Other long-term liabilities	228			111
Total long-term liabilities	123,398			106,020
Commitments and contingencies (Note 13)
SHAREHOLDERS' EQUITY:
Common stock, no par value; unlimited shares authorized; 68,375,282 and 66,432,609 shares issued and outstanding at March 31, 2013 and December 31, 2012, respectively	316,346			316,346
Additional paid-in capital	28,925			28,336
Accumulated deficit	(299,373		)	(294,787		)
Total shareholders' equity	45,898			49,895
Non-controlling interest:
Preferred stock of subsidiary, aggregate liquidation preference $98,781 at March 31, 2013 and December 31, 2012, respectively	76,638			76,641
Total equity	122,536			126,536
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	314,982		$	290,068

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

4

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months Ended March 31,
	2013			2012
	(in thousands, except share and per share data)
REVENUES:
Natural gas	$	11,233		$	6,911
Condensate and oil	6,126			1,883
NGLs	3,542			1,884
Total natural gas, condensate, oil and NGLs revenues	20,901			10,678
Unrealized hedge loss	(9,637		)	(1,524		)
Total revenues	11,264			9,154
EXPENSES:
Production taxes	643			453
Lease operating expenses	1,837			2,416
Transportation, treating and gathering	1,164			1,179
Depreciation, depletion and amortization	5,365			5,653
Accretion of asset retirement obligation	102			94
General and administrative expense	3,002			3,161
Litigation settlement expense	1,000			1,250
Total expenses	13,113			14,206
LOSS FROM OPERATIONS	(1,849		)	(5,052		)
OTHER INCOME (EXPENSE):
Interest expense	(609		)	(27		)
Investment income and other	3			2
Foreign transaction (loss) gain	(1		)	3
LOSS BEFORE PROVISION FOR INCOME TAXES	(2,456		)	(5,074		)
Provision for income taxes	—			—
NET LOSS	(2,456		)	(5,074		)
Dividend on preferred stock attributable to non-controlling interest	(2,130		)	(1,236		)
NET LOSS ATTRIBUTABLE TO GASTAR EXPLORATION LTD.	$	(4,586	)	$	(6,310	)
NET LOSS PER COMMON SHARE ATTRIBUTABLE TO GASTAR EXPLORATION LTD. COMMON SHAREHOLDERS:
Basic	$	(0.07	)	$	(0.10	)
Diluted	$	(0.07	)	$	(0.10	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic	63,864,527			63,336,437
Diluted	63,864,527			63,336,437

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

5

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Three Months Ended March 31,
	2013			2012
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(2,456	)	$	(5,074	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	5,365			5,653
Stock-based compensation	823			892
Unrealized hedge loss	9,637			1,524
Realized gain on derivative contracts	—			(220		)
Amortization of deferred financing costs	78			42
Accretion of asset retirement obligation	102			94
Changes in operating assets and liabilities:
Accounts receivable	295			5,429
Prepaid expenses	82			26
Accounts payable and accrued liabilities	(2,997		)	(4,633		)
Net cash provided by operating activities	10,929			3,733
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of natural gas and oil properties	(33,829		)	(35,494		)
Deposit for purchase of natural gas and oil properties	(7,425		)	—
Advances to operators	(2,713		)	(1,911		)
Proceeds (use of proceeds) from non-operators	16,090			(1,245		)
Purchase of furniture and equipment	(19		)	(120		)
Net cash used in investing activities	(27,896		)	(38,770		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility	19,000			24,000
Repayment of revolving credit facility	(2,000		)	(19,000		)
Proceeds from issuance of preferred stock, net of issuance costs	—			30,769
Dividend on preferred stock attributable to non-controlling interest	(1,420		)	(1,236		)
Deferred financing charges	(143		)	(267		)
Other	(236		)	(230		)
Net cash provided by financing activities	15,201			34,036
NET DECREASE IN CASH AND CASH EQUIVALENTS	(1,766		)	(1,001		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	8,901			10,647
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	7,135		$	9,646

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

6

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2013			December 31, 2012
	(Unaudited)
	(in thousands, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	7,089		$	8,892
Accounts receivable, net of allowance for doubtful accounts of $542 and $546, respectively	8,288			9,539
Commodity derivative contracts	1,217			7,799
Prepaid expenses	837			919
Total current assets	17,431			27,149
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, excluded from amortization	74,865			67,892
Proved properties	699,400			671,185
Total natural gas and oil properties	774,265			739,077
Furniture and equipment	1,944			1,925
Total property, plant and equipment	776,209			741,002
Accumulated depreciation, depletion and amortization	(490,117		)	(484,752		)
Total property, plant and equipment, net	286,092			256,250
OTHER ASSETS:
Commodity derivative contracts	854			1,369
Deferred charges, net	825			836
Advances to operators and other assets	2,153			4,275
Deposit for purchase of natural gas and oil properties	7,425			—
Total other assets	11,257			6,480
TOTAL ASSETS	$	314,780		$	289,879
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	18,214		$	23,863
Revenue payable	7,563			8,801
Accrued interest	172			151
Accrued drilling and operating costs	2,888			3,907
Advances from non-operators	33,630			17,540
Commodity derivative contracts	3,491			1,399
Accrued litigation settlement liability	1,000			—
Asset retirement obligation	358			358
Other accrued liabilities	1,611			1,480
Total current liabilities	68,927			57,499
LONG-TERM LIABILITIES:
Long-term debt	115,000			98,000
Commodity derivative contracts	1,725			1,304
Asset retirement obligation	6,438			6,598
Due to parent	31,362			30,903
Other long-term liabilities	228			111
Total long-term liabilities	154,753			136,916
Commitments and contingencies (Note 13)
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value; 10,000,000 shares authorized; 3,951,254 shares issued and outstanding at March 31, 2013 and December 31, 2012, respectively, with liquidation preference of $25.00 per share	40			40
Common stock, no par value; 1,000 shares authorized; 750 shares issued and outstanding	237,431			237,431
Additional paid-in capital	76,598			76,601
Accumulated deficit	(222,969		)	(218,608		)
Total stockholders' equity	91,100			95,464
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	314,780		$	289,879

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

7

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months Ended March 31,
	2013			2012
	(in thousands, except share and per share data)
REVENUES:
Natural gas	$	11,233		$	6,911
Condensate and oil	6,126			1,883
NGLs	3,542			1,884
Total natural gas, condensate, oil and NGLs revenues	20,901			10,678
Unrealized hedge loss	(9,637		)	(1,524		)
Total revenues	11,264			9,154
EXPENSES:
Production taxes	643			453
Lease operating expenses	1,837			2,416
Transportation, treating and gathering	1,164			1,179
Depreciation, depletion and amortization	5,365			5,653
Accretion of asset retirement obligation	102			94
General and administrative expense	2,781			2,771
Litigation settlement expense	1,000			1,250
Total expenses	12,892			13,816
LOSS FROM OPERATIONS	(1,628		)	(4,662		)
OTHER INCOME (EXPENSE):
Interest expense	(609		)	(28		)
Investment income and other	5			2
Foreign transaction gain	1			2
LOSS BEFORE PROVISION FOR INCOME TAXES	(2,231		)	(4,686		)
Provision for income taxes	—			—
NET LOSS	(2,231		)	(4,686		)
Dividend on preferred stock	(2,130		)	(1,236		)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDER	$	(4,361	)	$	(5,922	)

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

8

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Three Months Ended March 31,
	2013			2012
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(2,231	)	$	(4,686	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	5,365			5,653
Stock-based compensation	823			892
Unrealized hedge loss	9,637			1,524
Realized gain on derivative contracts	—			(220		)
Amortization of deferred financing costs	78			42
Accretion of asset retirement obligation	102			94
Changes in operating assets and liabilities:
Accounts receivable	295			5,427
Prepaid expenses	58			7
Accounts payable and accrued liabilities	(3,105		)	(4,707		)
Net cash provided by operating activities	11,022			4,026
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of natural gas and oil properties	(33,829		)	(35,494		)
Deposit for purchase of natural gas and oil properties	(7,425		)	—
Advances to operators	(2,713		)	(1,911		)
Proceeds (use of proceeds) from non-operators	16,090			(1,245		)
Purchase of furniture and equipment	(19		)	(120		)
Net cash used in investing activities	(27,896		)	(38,770		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility	19,000			24,000
Repayment of revolving credit facility	(2,000		)	(19,000		)
Proceeds from issuance of preferred stock, net of issuance costs	—			30,769
Dividend on preferred stock	(1,420		)	(1,236		)
Deferred financing charges	(143		)	(267		)
Distribution to Parent, net	(363		)	(497		)
Other	(3		)	—
Net cash provided by financing activities	15,071			33,769
NET DECREASE IN CASH AND CASH EQUIVALENTS	(1,803		)	(975		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	8,892			10,595
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	7,089		$	9,620

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

9

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Description of Business

Gastar Exploration Ltd. is an independent energy company engaged in the exploration, development and production of natural gas, condensate, oil and NGLs in the United States (“U.S.”). Gastar Exploration Ltd.’s principal business activities include the identification, acquisition, and subsequent exploration and development of natural gas and oil properties with an emphasis on unconventional reserves, such as shale resource plays. Gastar Exploration Ltd. is currently pursuing the development of liquids-rich natural gas in the Marcellus Shale in West Virginia and is in the early stages of exploring and developing the Hunton Limestone horizontal oil play in Oklahoma. Gastar Exploration Ltd. also holds prospective Marcellus Shale acreage in Pennsylvania and producing natural gas acreage in the deep Bossier play in East Texas. The Company entered into a definitive agreement to sell the East Texas assets on April 19, 2013.

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, 2012 (“2012 Form 10-K”) filed with the SEC. Please refer to the notes to the financial statements included in the 2012 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. All material items included in those notes have not changed except as a result of normal transactions in the interim or as disclosed within this report.

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 2012 Form 10-K. The current interim period reported herein should be read in conjunction with the financial statements and accompanying notes, including Item 8. “Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies” included in the 2012 Form 10-K.

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

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

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

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

The results of operations for the three months endedMarch 31, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013. In preparing these financial statements, the Company has evaluated events

10

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

Management does not believe that there are any recently issued and effective, or not yet effective, pronouncements as of March 31, 2013 that would have, or are expected to have, any significant effect on the Company's consolidated financial position, cash flows or results of operations.

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 and Oklahoma.

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

	March 31, 2013		December 31, 2012
	(in thousands)
Unproved properties, excluded from amortization:
Drilling in progress costs	$	5,926	$	1,902
Acreage acquisition costs	65,002		62,395
Capitalized interest	3,937		3,595
Total unproved properties excluded from amortization	$	74,865	$	67,892

For the three months endedMarch 31, 2013 and 2012, management's evaluation of unproved properties did not result in an impairment.

The full cost method of accounting for natural gas and oil properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full cost ceiling calculation. The ceiling is the present value of estimated future cash flow from proved natural gas, condensate, oil and NGLs reserves reduced by future operating expenses, development expenditures, abandonment costs (net of salvage) to the extent not included in natural gas and oil properties pursuant to authoritative guidance and estimated future income taxes thereon. To the extent that our capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense. Once incurred, this impairment of natural gas and oil properties is not reversible at a later date even if natural gas and oil prices increase. The ceiling calculation dictates that the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices and costs in effect are held constant indefinitely. The 12-month unweighted arithmetic average of the first-day-of-the-month prices are adjusted for basis and quality differentials in determining the present value of the reserves. The table below sets forth relevant assumptions utilized in the quarterly ceiling test computations for the respective periods noted:

	March 31, 2013
Henry Hub natural gas price (per MMBtu) (1)	$	2.95
West Texas Intermediate oil price (per Bbl) (1)	$	89.17
Impairment recorded (pre-tax) (in thousands)	$	—

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	March 31, 2012
Henry Hub natural gas price (per MMBtu) (1)	$	3.73
West Texas Intermediate oil price (per Bbl) (1)	$	94.65
Impairment recorded (pre-tax) (in thousands)	$	—

 _________________________________

(1) For the respective periods, natural gas and oil prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices.

Future declines in the 12-month average of natural gas, condensate, oil and NGLs prices could result in the recognition of future ceiling impairments.

Chesapeake Acquisition

On March 28, 2013, Gastar USA entered into a Purchase and Sale Agreement by and among Chesapeake Exploration, L.L.C., Arcadia Resources, L.P., Jamestown Resources, L.L.C., Larchmont Resources, L.L.C. (together, the “Chesapeake Parties”) and Gastar USA (the “Chesapeake Purchase Agreement”). Pursuant to the Chesapeake Purchase Agreement, Gastar USA will acquire approximately 157,000 net acres of Oklahoma oil and gas leasehold interests from the Chesapeake Parties, including production from interests in 176 producing wells located in Oklahoma, for a cash purchase price of approximately $74.2 million, subject to customary adjustments. The Chesapeake Purchase Agreement contains customary representations and warranties and covenants, including provisions for indemnification, subject to the limitations described in the Chesapeake Purchase Agreement. The closing of the proposed property acquisition is subject to satisfaction of customary closing conditions and delivery of the total acquisition purchase price of approximately $74.2 million (subject to adjustment for an acquisition effective date of October 1, 2012) on or before June 7, 2013. In the event that Gastar does not close the acquisition by such date, the Chesapeake Parties may terminate the property acquisition agreement. A copy of the Chesapeake Purchase Agreement, dated March 28, 2013, is filed herewith as Exhibit 2.1 to this Form 10-Q and is incorporated herein by reference.

Hilltop Area, East Texas Sale

On April 19, 2013, Gastar Exploration Texas, LP (“Gastar Texas”) and Gastar USA entered into a Purchase and Sale Agreement by and among Gastar Texas, Gastar USA and Cubic Energy, Inc. (“Cubic Energy”) (the “East Texas Sale Agreement”). Pursuant to the East Texas Sale Agreement, Cubic Energy will acquire from Gastar Texas approximately 31,800 gross (16,300 net) acres of leasehold interests in the Hilltop area of East Texas in Leon and Robertson Counties, Texas, including production from interests in producing wells, for a cash purchase price of approximately $46.0 million, subject to adjustment for accounting effective date of January 1, 2013 and other customary adjustments. The East Texas Sale Agreement contains customary representations and warranties and covenants, including provisions for indemnification, subject to the limitations described in the East Texas Sale Agreement. The closing of the sale is anticipated to occur on or before June 5, 2013 and is subject to satisfaction of customary closing conditions. A copy of the East Texas Sale Agreement, dated April 19, 2013, is filed herewith as Exhibit 2.2 to this Form 10-Q and is incorporated herein by reference.

Atinum Joint Venture

In September 2010, Gastar USA entered into a joint venture (the “Atinum Joint Venture”) pursuant to which Gastar USA assigned to an affiliate of Atinum Partners Co., Ltd. (“Atinum”), for $70.0 million in total consideration, an initial 21.43% interest in all of its existing Marcellus Shale assets in West Virginia and Pennsylvania at that date, which consisted 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”). In early 2012, Gastar USA made additional assignments to Atinum as a result of which Atinum owns a 50% interest in the Atinum Joint Venture Assets. Subsequent to December 31, 2011, Atinum funds only its 50% share of costs. Effective June 30, 2011, an AMI was established for additional acreage acquisitions in Ohio, New York, Pennsylvania and West Virginia, excluding the counties of Pendleton, Pocahontas, Preston, Randolph and Tucker, West Virginia. Within this AMI, Gastar USA acts 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.

The Atinum Joint Venture's initial three-year development program called for the partners to drill a minimum of 12 horizontal wells in 2011 and 24 operated horizontal wells in each of 2012 and 2013, respectively, for a total of 60 wells to be drilled. At December 31, 2012, 38 gross operated wells were on production under the Atinum Joint Venture. Due to natural gas price declines, Atinum and Gastar USA agreed to reduce the 2013 minimum wells to be drilled requirement to 19 wells which will result in 57 gross wells on production at December 31, 2013, compared to the 60 gross wells originally agreed upon.

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4. Long-Term Debt

Amended and Restated Revolving Credit Facility

On October 28, 2009, Gastar USA, together with the other parties thereto, entered into an amended and restated 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. 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 0.5% is payable quarterly based on the unutilized balance of the borrowing base. The Revolving Credit Facility had a scheduled maturity date of January 2, 2013.

The Revolving Credit Facility is guaranteed by Parent (as defined in the Revolving Credit Facility) 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 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, incurrence of other indebtedness without lenders' consent and 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 become due and payable upon the occurrence of certain usual and customary events of default, including among others:

• Failure to make payments;

• 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 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.

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, the Third Amendment (as defined below), the Fourth Amendment (as defined below) and the Fifth 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 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 pay cash dividends on the Series A Preferred Stock of no more than $10.0 million in

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the aggregate in each calendar year and as long as payment of such dividends does not exceed 10% of the current availability under the then existing borrowing base.

On December 2, 2011, Gastar USA, together with the parties thereto, entered into the Fourth Amendment to the Credit Agreement, effective as of November 10, 2011 (the “Fourth Amendment”). The Fourth Amendment amended the Revolving Credit Facility, by, among other things, (i) extending the maturity date on borrowings under the Revolving Credit Facility to September 30, 2015; (ii) allowing Gastar USA to hedge up to 100% of the PDP reserves reflected in its reserve report using hedging other than floors and protective spreads; and (iii) allowing no more than ten separate LIBO Rate Loans to be outstanding at one time.

On March 6, 2013, Gastar USA, together with the parties thereto, entered into the Waiver and Fifth Amendment to the Credit Agreement, effective as of March 6, 2013 (the “Fifth Amendment”). The Fifth Amendment amended the Revolving Credit Facility, by (i) increasing the permitted term of commodity hedging agreements to five years from three years; (ii)reducing the minimum ratio of current assets to current liabilities that is required from 1.0 to 1.0 to 0.6 to 1.0 for quarters ending from March 31, 2013 through December 31, 2013, and making certain changes in the calculation of current liabilities for such dates to exclude advances from non-operators; (iii) reducing the amount of available commitment that is required immediately prior to and after giving effect to the payment of cash dividends on or the redemption of the Gastar USA Series A Preferred Stock to 5% from 10% of current availability; (iv) increasing the amount of cash dividends on the Gastar USA Series A Preferred Stock that can be paid in the aggregate in each calendar year to $12.1 million from $10 million; and (v) modifying the manner in which EBITDA is determined for purposes of the required ratios of total net indebtedness to EBITDA and EBITDA to interest expense with respect to the calendar quarter ending March 31, 2013.

Borrowing base redeterminations are scheduled semi-annually in May and November of each calendar year. Gastar USA and its lenders may request one additional unscheduled redetermination annually. As of December 31, 2011, the Revolving Credit Facility had a borrowing base of $50.0 million, with $30.0 million of borrowings outstanding and availability of $20.0 million. Gastar USA requested that the May 2012 redetermination be accelerated to March 2012. On March 5, 2012, Gastar USA was notified by its lenders that, effective immediately, the borrowing base was increased from $50.0 million to $100.0 million. Gastar USA requested that the November 2012 redetermination be accelerated to September 2012. On October 19, 2012, Gastar USA was notified by its lenders that, effective September 30, 2012, the borrowing base was increased from $100.0 million to $110.0 million. Gastar USA requested one unscheduled borrowing base redetermination in December 2012. On January 29, 2013, Gastar USA was notified by its lenders that, effective December 31, 2012, the borrowing base was increased from $110.0 million to $125.0 million. Gastar USA requested that the May 2013 redetermination be accelerated to March 2013. On April 30, 2013, Gastar USA was notified by its lenders that, effective as of March 31, 2013, the borrowing base was increased from $125.0 million to $160.0 million. At March 31, 2013, the Revolving Credit Facility had a borrowing base of $160.0 million, with $115.0 million of borrowings outstanding and availability of $45.0 million. The next regularly scheduled redetermination is set for November 2013.

At March 31, 2013, 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 March 31, 2013 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, unproved properties 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. The Company assesses its unproved properties for impairment whenever events or circumstances indicate the carrying value of those properties may not be recoverable. The fair value of the unproved properties is measured using an income approach based upon internal estimates of future production levels, current and future prices, drilling and operating costs, discount rates, current drilling plans and favorable and unfavorable drilling activity on the properties being evaluated and/or adjacent properties, which are Level 3 inputs. For the three months endedMarch 31, 2013 and 2012, management's evaluation of unproved properties did not result in an impairment. As no other fair value measurements are required to be recognized on a non-recurring basis at March 31, 2013, no additional disclosures are provided at March 31, 2013.

As defined in the guidance, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation

14

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. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Level 3 instruments are commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge natural gas, oil and NGLs price risk. 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. The fair values derived from counterparties and third-party brokers are verified by the Company using publicly available values for relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location. Although such counterparty and third-party broker quotes are used to assess the fair value of its commodity derivative instruments, the Company does not have access to the specific assumptions used in its counterparties valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided and the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments.

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 consolidated balance sheets.

Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the 2013 and 2012 periods.

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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 March 31, 2013 and December 31, 2012:

	Fair value as of March 31, 2013
	Level 1		Level 2		Level 3			Total
	(in thousands)
Assets:
Cash and cash equivalents	$	7,135	$	—	$	—		$	7,135
Commodity derivative contracts	—		—		2,071			2,071
Liabilities:
Commodity derivative contracts	—		—		(5,216		)	(5,216		)
Total	$	7,135	$	—	$	(3,145	)	$	3,990
	Fair value as of December 31, 2012
	Level 1		Level 2		Level 3			Total
	(in thousands)
Assets:
Cash and cash equivalents	$	8,901	$	—	$	—		$	8,901
Commodity derivative contracts	—		—		9,168			9,168
Liabilities:
Commodity derivative contracts	—		—		(2,703		)	(2,703		)
Total	$	8,901	$	—	$	6,465		$	15,366

The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the three months endedMarch 31, 2013 and 2012. 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 March 31, 2013 and 2012.

	Three Months Ended March 31,
	2013			2012
	(in thousands)
Balance at beginning of period	$	6,465		$	15,873
Total gains (losses) (realized or unrealized):
included in earnings	(4,002		)	872
included in other comprehensive income	—			—
Purchases	—			—
Issuances	—			—
Settlements (1)	(5,608		)	(3,289		)
Transfers in and (out) of Level 3	—			—
Balance at end of period	$	(3,145	)	$	13,456
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 March 31, 2013 and 2012	$	(9,637	)	$	(1,524	)

 _________________________________

(1) Included in total revenues on the statement of operations.

At March 31, 2013, 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 March 31, 2013 approximates the respective carrying value because the interest rate approximates the current market rate (Level 2).

The Company has consistently applied the valuation techniques discussed above in all periods presented.

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The fair value guidance, as amended, establishes that every derivative instrument is to be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 6, “Derivative Instruments and Hedging Activity.”

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, condensate, oil and NGLs 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 hedge gain (loss), while realized gains and losses related to contract settlements are recognized in natural gas, condensate, oil and NGLs revenues. For the three months ended March 31, 2013 and 2012, the Company reported unrealized losses of $9.6 million and $1.5 million, respectively, in the condensed consolidated statement of operations related to the change in the fair value of its commodity derivative instruments.

As of March 31, 2013, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:

Settlement Period	Derivative Instrument	Average Daily Volume	Total of Notional Volume	Base Fixed Price			Floor (Long)		Short Put		Call (Long)		Ceiling (Short)
		(in MMBtu's)
2013	Fixed price swap	2,165	595,500	$	3.85		$	—	$	—	$	—	$	—
2013	Fixed price swap	2,165	595,500	4.00			—		—		—		—
2013	Fixed price swap	3,000	825,000	4.06			—		—		—		—
2013	Fixed price swap	2,500	687,500	4.05			—		—		—		—
2013	Fixed price swap	13,495	3,711,000	3.87			—		—		—		—
2013 (1)	Fixed price swap	2,500	535,000	4.05			—		—		—		—
2013 (2)	Protective spread	2,500	152,500	4.05			—		3.79		—		—
2013 (3)	Protective spread	4,025	490,992	3.70			—		3.00		—		—
2013 (1)	Costless collar	2,500	535,000	—			5.00		—		—		6.45
2013 (2)	Costless three-way collar	2,500	152,500	—			5.00		4.00		—		6.45
2013	Call spread	2,500	687,500	—			—		—		4.75		5.25
2013	Basis - HSC (4)	4,000	1,100,000	(0.11		)	—		—		—		—
2014	Short calls	2,500	912,500	—			—		—		—		4.59
2014	Costless three-way collar	10,500	3,832,500	—			3.88		3.00		—		4.53
2014	Fixed price swap	11,136	4,064,500	4.06			—		—		—		—

 _______________________________

(1) For the period April to October 2013

(2) For the period November to December 2013

(3) For the period April to July 2013

(4) East Houston-Katy - Houston Ship Channel

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As of March 31, 2013, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:

Settlement Period	Derivative Instrument	Average Daily Volume (1)	Total of Notional Volume	Base Fixed Price		Floor (Long)		Short Put		Ceiling (Short)
		(in Bbls)
2013	Fixed price swap	135	37,000	$	92.80	$	—	$	—	$	—
2013	Fixed price swap	161	44,300	92.80		—		—		—
2013	Protective spread	400	110,000	92.80		—		70.00		—
2014	Producer three-way collar	200	73,000	—		90.00		70.00		106.20
2014	Fixed price swap	270	98,500	90.77		—		—		—
2015	Producer three-way collar	345	126,100	—		85.00		65.00		97.80
2016	Producer three-way collar	275	100,600	—		85.00		65.00		95.10
2017	Producer three-way collar	242	88,150	—		80.00		60.00		98.70

 _______________________________

(1) Crude volumes hedged include oil, condensate and certain components of our NGLs production.

As of March 31, 2013, the following NGLs derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:

Settlement Period	Derivative Instrument	Average Daily Volume	Total of Notional Volume	Base Fixed Price
		(in Bbls)
2013	Fixed price swap	300	82,500	$	39.50

As of March 31, 2013, all of the Company’s economic derivative hedge positions were with multinational energy companies 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 March 31, 2013 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.

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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 condensed consolidated statement of financial position and derivative gains and losses in the condensed consolidated statement of operations for derivative instruments that are not designated as hedging instruments:

	Fair Values of Derivative Instruments Derivative Assets (Liabilities)
		Fair Value
	Balance Sheet Location	March 31, 2013			December 31, 2012
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Current assets	$	1,217		$	7,799
Commodity derivative contracts	Other assets	854			1,369
Commodity derivative contracts	Current liabilities	(3,491		)	(1,399		)
Commodity derivative contracts	Long-term liabilities	(1,725		)	(1,304		)
Total derivatives not designated as hedging instruments		$	(3,145	)	$	6,465
	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	March 31, 2013			March 31, 2012
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Natural gas, condensate, oil and NGLs revenues	$	5,635		$	2,440
Commodity derivative contracts	Unrealized hedge loss	(9,637		)	(1,524		)
Commodity derivative contracts	Interest expense	—			(44		)
Total		$	(4,002	)	$	872

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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 Stock Incentive Plan (the “2006 Plan”) for the periods indicated:

	For the Three Months Ended March 31, 2013
Other share issuances:
Restricted common shares granted	2,177,903
Restricted common shares vested	629,029
Common shares surrendered upon vesting (1)	188,903
Common shares forfeited	66,327

 __________________

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

On June 7, 2012, Parent's shareholders voted to approve the Second Amendment to the 2006 Plan. This amendment, effective June 3, 2012, increased the total number of shares available for issuance under the plan from 6,000,000 shares to 11,000,000 shares. There were 2,519,757 shares available for issuance under the 2006 Plan at March 31, 2013.

Shares Reserved

At March 31, 2013, Parent had 939,100 common shares reserved for the exercise of stock options.

Shares Owned by Chesapeake Energy Corporation

On March 28, 2013, the Company entered into a Settlement Agreement, dated March 28, 2013, between Chesapeake Exploration, L.L.C. and Chesapeake Energy Corporation (collectively, “Chesapeake”) and the Company, Gastar Exploration Texas, LP and Gastar Exploration Texas, LLC (the “Settlement Agreement”). Pursuant to the Settlement Agreement, the Company will settle and resolve all claims of Chesapeake and its subsidiaries against the Company and its subsidiaries made in a previously disclosed lawsuit filed in the U.S. District Court for the Southern District of Texas. In order to effect a mutual full and unconditional release and settlement of all claims made in the lawsuit filed by Chesapeake, the Company will pay Chesapeake approximately $10.8 million in cash, approximately $9.8 million of which will be paid for the repurchase of 6,781,768 outstanding common shares of Parent currently held by Chesapeake Energy Corporation. The closing of the stock repurchase and settlement is subject to satisfaction of customary closing conditions and delivery of the stock repurchase price of $9.8 million on or before June 7, 2013. See Note 13, “Commitments and Contingencies.”

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 March 31, 2013 and December 31, 2012, all of which were held by Parent.

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

Gastar USA Preferred Stock

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

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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).

For the three months endedMarch 31, 2013, Gastar USA did not sell any shares of Series A Preferred Stock under its at the market preferred share purchase agreement (the “ATM Agreement”). At March 31, 2013, there were 3,951,254 total shares of Series A Preferred Stock issued and outstanding. From April 1, 2013 to May 1, 2013, Gastar USA sold an additional 6,906 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $136,000.

The Series A Preferred Stock is 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. 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
On or after June 23, 2012 and prior to June 23, 2013	$	25.50
On or after June 23, 2013 and prior to June 23, 2014	$	25.25
On or after June 23, 2014	$	25.00

Gastar USA will pay cumulative dividends on the Series A Preferred Stock at a fixed rate of 8.625% per annum of the $25.00 per share liquidation preference. For the three months ended March 31, 2013, Gastar USA paid dividends of $1.4 million.

8. Equity Compensation Plans

Share-Based Compensation Plan

Pursuant to the 2006 Plan, as amended, the Company's Compensation Committee agreed to allocate a portion of the 2013 long-term incentive grants to executives as performance based units (“PBUs”). The PBUs represent a contractual right to receive shares of Parent's common stock, an amount of cash equal to the fair market value of a share of Parent's common stock, or a combination of shares of Parent's common stock and cash as of the date of settlement based on the number of PBUs to be settled. The settlement of PBUs may range from 0% to 200% of the targeted number of PBUs stated in the agreement contingent upon the achievement of certain share price appreciation targets as compared to a peer group index. The PBUs vest equally and settlement is determined annually over a three year period. Any PBUs not vested at each measurement date will expire.

Compensation expense associated with PBUs is based on the grant date fair value of a single PBU as determined using a Monte Carlo simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the PBUs with shares of Parent's common stock at each measurement date, the PBU awards are accounted for as equity awards and the expense is calculated on the grant date assuming a 100% target payout and amortized over the life of the PBU award.

The table below provides a summary of PBUs as of the date indicated:

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	PBUs	Fair Value per Unit
Unvested PBUs at December 31, 2012	—	$	—
Granted	1,192,889	1.56
Vested	—	—
Forfeited	—	—
Unvested PBUs at March 31, 2013	1,192,889	$	1.56

For the quarter ended March 31, 2013, the Company recognized $202,000 of compensation expense associated with the PBUs granted on January 30, 2013.

9. Interest Expense

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

	For the Three Months Ended March 31,
	2013			2012
	(in thousands)
Interest expense:
Cash and accrued	$	900		$	289
Amortization of deferred financing costs	78			42
Capitalized interest	(369		)	(304		)
Total interest expense	$	609		$	27

10. Related Party Transactions

Chesapeake Energy Corporation

Chesapeake Energy Corporation acquired 6,781,768 of Parent’s common shares during 2005 to 2007 in a series of private placement transactions. As a result of its share ownership, Chesapeake Energy Corporation has the right to have an observer present at meetings of the Parent’s board of directors.

On March 28, 2013, the Company entered into a Settlement Agreement between Chesapeake Exploration, L.L.C. and Chesapeake Energy Corporation (collectively, “Chesapeake”) and the Company, Gastar Exploration Texas, LP and Gastar Exploration Texas, LLC (the “Settlement Agreement”). Pursuant to the Settlement Agreement, the Company will settle and resolve all claims of Chesapeake and its subsidiaries against the Company and its subsidiaries made in a previously disclosed lawsuit filed in the U.S. District Court for the Southern District of Texas. In order to effect a mutual full and unconditional release and settlement of all claims made in the lawsuit filed by Chesapeake, the Company will pay Chesapeake approximately $10.8 million in cash, approximately $9.8 million of which will be paid for the repurchase of 6,781,768 outstanding common shares of Parent currently held by Chesapeake. The closing of the stock repurchase and settlement is subject to satisfaction of certain closing conditions and delivery of the stock repurchase price of $9.8 million on or before June 7, 2013. See Note 7, “Capital Stock - Shares Owned by Chesapeake Energy Corporation.”

As of March 31, 2013, Chesapeake Energy Corporation owned 6,781,768 of Parent’s common shares, or 9.9% of the Parent’s outstanding common shares.

11. Income Taxes

For the three months endedMarch 31, 2013 and 2012, respectively, the Company did not recognize a current income tax benefit or provision due to the Company being in a net operating loss position for both periods.

12. 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

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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 March 31,
	2013			2012
	(in thousands, except per share and share data)
Net loss attributable to Gastar Exploration Ltd.	$	(4,586	)	$	(6,310	)
Weighted average common shares outstanding - basic	63,864,527			63,336,437
Weighted average common shares outstanding - diluted	63,864,527			63,336,437
Net loss per common share attributable to Gastar Exploration Ltd. Common Shareholders:
Basic	$	(0.07	)	$	(0.10	)
Diluted	$	(0.07	)	$	(0.10	)
Common shares excluded from denominator as anti-dilutive:
Unvested restricted shares	2,631,552			1,216,534
Stock options	949,100			817,600
PBUs	1,192,889			—
Total	4,773,541			2,034,134

13. Commitments and Contingencies

Litigation

Chesapeake Exploration L.L.C. (“Chesapeake Exploration”) and Chesapeake Energy Corp.  (“Chesapeake Energy”) v. Gastar Exploration Ltd., Gastar Exploration Texas, LP, and Gastar Exploration Texas, LLC (No. 4:12-cv-2922), United States District Court for the Southern District of Texas, Houston Division.  This lawsuit, filed on October 1, 2012, re-asserts the same claims for rescission of the November 2005 Agreements (as defined below) and for recovery of amounts paid under those agreements that Chesapeake Exploration and Chesapeake Energy (collectively, “Chesapeake”) previously asserted in the cross-action filed against the Company in the Navasota litigation described below, as previously disclosed in the Company's filings. In March 2011, Chesapeake dismissed its cross-claims against the Company in the Navasota litigation, without prejudice to their re-filing. In this new lawsuit, Chesapeake re-asserts those claims, seeking rescission of (a) a Purchase and Sale and Exploration and Development Agreement between the Company and Chesapeake Exploration Limited Partnership (the “Purchase and Sale Agreement”), relating to properties in the Hilltop Prospect in Texas, (b) an Exploration and Development Agreement between the Company and Chesapeake Exploration Limited Partnership, (c) a Common Share Purchase Agreement between the Company and Chesapeake Energy, and (d) a Registration Rights Agreement between the Company and Chesapeake Energy, all effective as of November 4, 2005 (collectively, “the November 2005 Agreements”), based on an alleged “mutual mistake” and alleged failure of consideration.  Chesapeake alleges that the parties to the November 2005 Agreements believed that the Gastar defendants had the right to convey to Chesapeake Exploration the properties that were the subject of the Purchase and Sale Agreement, notwithstanding the exercise by Navasota Resources LP (“Navasota”) of a preferential right to purchase the interest in the Hilltop Prospect properties. The dispute over the validity of Navasota's exercise of its preferential right to purchase was the subject of litigation filed by Navasota prior to the execution of the November 2005 Agreements.  Chesapeake claims that the Texas Court of Appeals' subsequent ruling in that litigation upholding the validity of Navasota's exercise of the preferential right to purchase establishes that there was a mutual mistake of fact and a failure of consideration with regard to the November 2005 Agreements. In the alternative, Chesapeake claims that the Gastar defendants have been unjustly enriched at the expense of Chesapeake by the funds paid by Chesapeake to the Gastar defendants. In their complaint filed in the lawsuit, Chesapeake offers to return Parent's common shares purchased pursuant to the Common Stock Purchase Agreement, and seeks restitution from the Gastar defendants of the net amount of approximately $101.4 million, which includes the $76.0 million that Chesapeake Energy paid for Parent's common shares (now 5,430,329 shares after a 1:5 stock split) that Chesapeake Energy purchased in 2005 and now seeks to return.  In a motion to compel arbitration filed by Chesapeake on October 24, 2012, Chesapeake asked the court to order arbitration of the claims asserted in the complaint pursuant to an arbitration clause in the Common Share Purchase Agreement.

The Gastar defendants responded to the lawsuit by filing a motion to dismiss, contending that the claims fail as a matter of law.  Specifically, the Gastar defendants contended in the motion to dismiss that all facts relating to the Navasota claim were

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fully known to the parties at the time of execution of the November 2005 Agreements, and the parties expressly agreed in the Purchase and Sale Agreement that Chesapeake Exploration would take title to the properties subject to Navasota's claim and would convey the properties to Navasota in the event Navasota prevailed in the litigation, precluding Chesapeake's claims for rescission of the November 2005 Agreements.  For the same reasons, the Gastar defendants also contended in the motion to dismiss that Chesapeake received all of the consideration that the November 2005 Agreements called for and that there was no failure of consideration.  With regard to Chesapeake's alternative unjust enrichment claim, the Gastar defendants contended in the motion to dismiss that it is barred by the two-year statute of limitations and that in any event, it fails for a variety of reasons, including the fact that the parties' agreements address the subject matter of the dispute (precluding a claim for unjust enrichment) and the fact that the Gastar defendants were not unjustly enriched by Chesapeake Exploration's payment of the share of costs attributable to an interest in the properties that was not owned by the Gastar defendants.   The Gastar defendants also contended in their response to the motion to compel arbitration that Chesapeake's claims are not subject to arbitration and that the claims should be resolved on the merits by the federal court in which Chesapeake filed the lawsuit.

On March 28, 2013, the Company entered into a Settlement Agreement between Chesapeake and the Gastar defendants (the “Settlement Agreement”). Pursuant to the Settlement Agreement, the Gastar defendants will settle and resolve all claims of Chesapeake and its subsidiaries against the Company and its subsidiaries made in the Chesapeake lawsuit. In order to affect a mutual full and unconditional release and settlement of all claims made in the lawsuit filed by Chesapeake, the Company will pay Chesapeake approximately $10.8 million in cash, approximately $9.8 million of which will be paid for the repurchase of 6,781,768 outstanding common shares of the Company currently held by Chesapeake Energy Corporation.

On the same day that the Company entered into the Settlement Agreement, Gastar USA entered into an agreement for the acquisition of certain properties from Chesapeake. The closing of the proposed property acquisition, stock repurchase and settlement for an aggregate $85.0 million is subject to satisfaction of customary closing conditions and delivery of the total acquisition purchase of approximately $74.2 million (subject to adjustment for an acquisition effective date of October 1, 2012) and stock repurchase price of approximately $9.8 million and an additional $1.0 million in cash on or before June 7, 2013. In the event that Gastar USA does not close the acquisition by such date, Chesapeake may terminate the property acquisition agreement, but the Company may elect to pay for the stock repurchase and effect the lawsuit settlement for total consideration of $15.0 million assuming sufficient funding is available. On March 31, 2013, following notification to the Court regarding the execution of the settlement agreement, the Court in the Chesapeake lawsuit entered an order of dismissal, without prejudice to the right of counsel of record to move for reinstatement of the case within 90 days in the event the settlement is not consummated.

As a result of the Settlement Agreement, as of March 31, 2013, an accrual for $1.0 million has been recorded for litigation settlement.

The Company has been expensing legal defense costs on these proceedings as they are incurred.

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.

14. Statement of Cash Flows – Supplemental Information

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

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	For the Three Months Ended March 31,
	2013			2012
	(in thousands)
Cash paid for interest	$	878		$	331
Non-cash transactions:
Capital expenditures excluded from accounts payable and accrued drilling costs	(4,167		)	(429		)
Capital expenditures excluded from accounts receivable	929			—
Capital expenditures excluded from prepaid expenses	24			153
Asset retirement obligation included in natural gas and oil properties	100			18
Asset retirement obligation assigned to operator	(362		)	—
Application of advances to operators	4,835			1,876
Other	(192		)	—

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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, oil and NGLs reserves;

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

• 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:

• our ability to successfully complete the acquisition of Mid-Continent assets from Chesapeake and integrate the acquired assets with ours and realize the anticipated benefits from the transaction;

• our ability to successfully complete the divestiture of our East Texas assets and realize anticipated uses of proceeds and improved liquidity position from that transaction;

• any unexpected costs or delays in connection with the Chesapeake acquisition or the East Texas divestiture;

• the supply and demand for natural gas, condensate, oil and NGLs;

• low and/or declining prices for natural gas, condensate, oil and NGLs;

• price volatility of natural gas, condensate, oil and NGLs;

• 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;

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• 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;

• 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 2012 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, condensate, oil and NGLs in the U.S. Our principal business activities include the identification, acquisition, and subsequent exploration and development of natural gas and oil properties with an emphasis on unconventional reserves, such as shale resource plays. We are currently pursuing the development of liquids-rich natural gas in the Marcellus Shale in West Virginia and are also in early stages of exploring and developing the Hunton Limestone horizontal oil play in Oklahoma. We hold prospective Marcellus Shale acreage in Pennsylvania and producing natural gas acreage in the deep Bossier gas play in the Hilltop area of East Texas. We have entered into a definitive agreement to sell our East Texas assets.

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 MKT under the symbol “GST.” Parent is a holding company. Substantially all of the Company’s operations are conducted through, and substantially all of its assets are held by, Parent’s

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primary operating subsidiary, Gastar USA, and its subsidiaries. Gastar USA’s Series A Preferred Stock is listed on the NYSE MKT under the symbol “GST.PRA.”

Our current operational activities are conducted primarily in the U.S. As of March 31, 2013, our major assets consist of approximately 99,100 gross (70,600 net) acres in the Marcellus Shale in West Virginia and southwestern Pennsylvania, approximately 54,300 gross (22,200 net) acres in Oklahoma and approximately 31,800 gross (16,300 net) acres in the Bossier play in the Hilltop area of East Texas. On March 28, 2013, we entered into a definitive agreement to purchase approximately 232,500 gross (157,000 net) acres in the Hunton Limestone play in Oklahoma. On April 19, 2013, we entered into a definitive agreement to sell the approximately 31,800 gross (16,300 net) acres in the Bossier play in the Hilltop area of East Texas.

The following discussion addresses material changes in our results of operations for the three months endedMarch 31, 2013 compared to the three months endedMarch 31, 2012 and material changes in our financial condition since December 31, 2012. 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 2012 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.

Marcellus Shale and Other Appalachia. 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 in the Appalachian Basin. Advancements in horizontal drilling and stimulation have produced promising results in the Marcellus Shale. These developments have resulted in increased leasing and drilling activity in the area. As of March 31, 2013, our acreage position in the play was approximately 99,100 gross (70,600 net) acres. We refer to the approximately 45,600 gross (20,900 net) acres reflecting our interest in our Marcellus Shale assets in West Virginia and Pennsylvania subject to the Atinum Joint Venture described below as our Marcellus West acreage. We refer to the approximately 53,400 gross (49,700 net) acres in Preston, Tucker, Pocahontas, Randolph and Pendleton Counties, West Virginia as our Marcellus East acreage. The entirety of our acreage is believed to be in the core, over-pressured area of the Marcellus play.

On September 21, 2010, we entered into the Atinum Joint Venture pursuant to which 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 at that date, 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”). In early 2012, we made additional assignments to Atinum as a result of which Atinum now owns a 50% interest in the Atinum Joint Venture Assets. Effective 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. 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.

The Atinum Joint Venture's initial three-year development program called for the partners to drill a minimum of 12 horizontal wells in 2011 and 24 horizontal wells in each of 2012 and 2013, respectively, resulting in a total of 60 gross operated wells to be drilled. Due to natural gas price declines, Atinum and Gastar USA agreed to reduce the 2012 and 2013 minimum wells to be drilled requirement resulting in a plan to drill and complete 57 gross (26.9 net) wells by December 31, 2013. As of March 31, 2013, we had drilled and completed 48 gross (22.4 net) operated wells. All of our 2012 Marcellus Shale well operations were, and all of our 2013 Marcellus Shale well operations will be, under the Atinum Joint Venture.

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As of March 31, 2013, our operated wells capable of production in Marshall County, West Virginia were comprised of the following:

Pad	Gross Well Count	Net Well Count	Working Interest	Net Revenue Interest	Average Lateral Length (in feet)(1)	Date on Production
Corley	4.0	1.6	40.8%	35.4%	4,700	December 2011
Simms	3.0	1.5	50.0%	43.2%	4,900	December 2011
Hall	3.0	1.2	40.0%	34.7%	4,300	January 2012
Hendrickson	5.0	2.0	40.0%	34.7%	4,600	April 2012
Accettolo	3.0	1.5	50.0%	40.2%	4,600	June 2012
Burch Ridge	5.0	2.5	50.0%	41.5%	5,500	August 2012
Wayne	4.0	2.0	50.0%	40.6%	5,000	September 2012
Wengerd	7.0	3.1	44.5%	37.7%	4,900	November 2012
Lily	4.0	2.0	50.0%	40.6%	5,300	December 2012
Shields	5.0	2.5	50.0%	41.5%	3,000	February 2013
Addison	5.0	2.5	50.0%	41.7%	5,000	March 2013
	48.0	22.4

 _________________________________

(1) Average well lateral length approximates the actual average well lateral length for the pad wells.

As of March 31, 2013 and currently as of the date of this report, we had drilling operations at various stages on the following wells in Marshall County, West Virginia:

Pad	Gross Well Count	Net Well Count	Working Interest	Estimated Net Revenue Interest	Average Lateral Length (in feet)(1)	Status	Estimated Production Date
Shields	5.0	2.5	50.0%	42.0%	3,800	Completion operations in progress	Second Quarter 2013
Goudy(2)	4.0	2.0	50.0%	40.5%	6,100	Drilling operations in progress	Early Third Quarter 2013
	9.0	4.5

 _________________________________

(1) Average well lateral length approximates the actual average well lateral length for wells that have been completed and the estimated average well lateral length for wells that have not been completed on a pad.

(2) Goudy pad to ultimately have nine wells. The last four wells are estimated to be on production early 2014.

For the three months endedMarch 31, 2013, net production from the Marcellus Shale averaged approximately 28.5 MMcfe/d compared to 14.0 MMcfe/d for the three months endedMarch 31, 2012. Since the inception of our operations in the Marcellus Shale in 2011, our operated production and sales in West Virginia have been curtailed by issues with condensate handling, dehydration limitations, high line pressures and excessive unscheduled system down-time on a third-party-operated gathering system. The gathering system operator has continually taken steps to resolve these issues. In May 2012, dehydration capacity was increased from 40 MMcf/d to 70 MMcf/d and compression was added to reduce line pressure to approximately 550 psi at the Corley CRP. In late March 2013, a second CRP was added at our Burch Ridge pad with 70 MMcf/d dehydration capacity, bringing total dehydration capacity for our natural gas production to 140 MMcf/d. In mid-April 2013, compression was added at the Burch Ridge CRP to reduce line pressures to approximately 550 psi. The third-party gathering system downtime during the first quarter of 2013 resulted in reduced production of approximately 16.8 MMcfe/d, or 42% of total production, for the quarter ended March 31, 2013 compared to reduced production of approximately 4.9 MMcfe/d, or 17% of total production, for the quarter ended March 31, 2012. We are continuing to work with the third-party gathering system operator to resolve recurring production curtailment issues on our operated Marcellus Shale wells. The addition of the Burch Ridge CRP coupled with compression at the location has recently increased our current daily gross production, although we are still experiencing material downtime and high-line pressures that cause our ability to produce natural gas and condensate to be negatively impacted. During the three months ended March 31, 2013, our first quarter average gross natural gas production

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was approximately 47.0 MMcf/d. For the month of April 2013, we averaged gross natural gas production of approximately 69 MMcf/d. Additionally, we have developed a plan that could be implemented prior to year end whereby a new third party would handle all of our condensate production, resulting in an increase in gross natural gas and condensate production rates and condensate pricing.

Mid-Continent Horizontal Oil Play. At March 31, 2013, we held leases covering approximately 54,300 gross (22,200 net) acres in Major, Garfield and Kingfisher Counties, Oklahoma in the Hunton Limestone horizontal oil play. Our leasing activities are continuing in the initial AMI prospect area and have been expanded to include two additional adjacent prospect areas. For the first 12,500 gross acres acquired in the initial AMI prospect, we paid 62.5% of lease acquisition costs for a 50% leasehold interest and 50% of lease acquisition costs on additional acres in excess of 12,500 gross acres acquired for a 50% working interest. In addition, in the initial AMI prospect area, we will pay 62.5% of the drilling and completions costs for the first four wells and 56.25% of the drilling and completions costs in the next four wells to earn a 50% working interest. For all subsequent wells in the initial AMI, we will pay 50% of the drilling and completions costs to earn a 50% working interest. We will pay 54.25% of all lease acquisition and drilling and completions costs in the two new prospect areas to earn a 50% working interest. Our approximate net revenue interest is 39.0% in all areas. A third-party operator handles all drilling, completion and production activities, and we handle all leasing and permitting activities.

As of March 31, 2013 and currently as of the date of this report, we had drilling operations at various stages on the following wells in Hunton Limestone formation:

				Average Production Rates(1)
Well Name	Current Working Interest	Current Approximate Net Revenue Interest	Approximate Lateral Length (in feet)	Oil (Bbl/d)	Natural Gas (Mcf/d)	BOE/d	Status	Approximate Net Costs to Drill & Complete ($ millions)
Mid-Con 1H	50.0%	39.0%	4,200	39	116	58	Producing - October 2012(2)	$3.1
Mid-Con 2H	50.0%	39.0%	4,100	998	1,026	1,169	Producing - April 2013(3)	$3.3
Mid-Con 3H(4)	70.9%	55.3%	4,300	—	—	—	Initial flow back - April 2013(5)	$3.7
Mid-Con 4H(6)	62.5%	48.8%	4,200	—	—	—	Initial flow back - May 2013	$3.3

 _________________________________

(1) Current production rates are based on the 30 days ended April 30, 2013.

(2) The Mid-Con 1H has recovered approximately 37% of completion fluids as of April 30, 2013.

(3) The Mid-Con 2H has recovered approximately 10% of completion fluids as of April 30, 2013.

(4) As a result of inclusion of non-consent interests, we are paying 70.9% of the drilling and completions costs to earn an approximate before payout 56.7% working interest and 44.2% net revenue interest. Upon payout of 500% of all drilling and completions costs and 300% of all operating costs, our working interest will be reduced to 50% with an approximate net revenue interest of 39%.

(5) The Mid-Con 3H is producing completion fluids at an average gross rate of 1,194 barrels of water per day with approximately 12% of completion fluids recovered as of April 30, 2013.

(6) We will ultimately own a 50% working interest and an approximate 39% net revenue interest in the Mid-Con 4H well.

The significant improvement in production rate on the Mid-Con 2H well is attributed to targeting the horizontal lateral deeper in the Hunton Limestone formation and increasing the number of fracs in the horizontal lateral. The Mid-Con 3H and 4H wells were drilled and completed in a similar manner as the Mid-Con 2H.

On March 28, 2013, Gastar USA entered into the Chesapeake Purchase Agreement. Pursuant to the Chesapeake Purchase Agreement, Gastar USA will acquire approximately 157,000 net acres of Oklahoma oil and gas leasehold interests from the Chesapeake Parties, including production from interests in 176 producing wells located in Oklahoma, for a cash purchase price of approximately $74.2 million, subject to customary adjustments. The Chesapeake Purchase Agreement contains customary representations and warranties and covenants, including provisions for indemnification, subject to the limitations described in

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the Chesapeake Purchase Agreement. The closing of the proposed property acquisition is subject to satisfaction of customary closing conditions and delivery of the total acquisition purchase price of approximately $74.2 million (subject to adjustment for an acquisition effective date of October 1, 2012) on or before June 7, 2013. In the event that Gastar does not close the acquisition by such date, the Chesapeake Parties may terminate the property acquisition agreement.

For the three months endedMarch 31, 2013, net production from the Mid-Continent averaged approximately 0.9 MMcfe/d, of which 84% was crude oil.

Hilltop Area, East Texas. At March 31, 2013, we held leases covering approximately 31,800 gross (16,300 net) acres in the Bossier play in the Hilltop area of East Texas in Leon and Robertson Counties. 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. Due to low natural gas prices, we suspended all Bossier drilling activities in the Hilltop area in 2012 and continuing into 2013. On April 19, 2013, we entered into the East Texas Sale Agreement to divest all of our leasehold interests and producing wells in the Hilltop area of East Texas in Leon and Robertson Counties, Texas for a cash purchase price of approximately $46.0 million, subject to adjustment for an accounting effective date of January 1, 2013 and other customary adjustments. The closing of the sale is anticipated to occur on or before June 5, 2013.

For the three months endedMarch 31, 2013, net production from the Hilltop area averaged approximately 11.0 MMcfe/d compared to 14.1 MMcfe/d for the three months endedMarch 31, 2012. The decrease in production is the result of natural field decline and the prior suspension of our East Texas drilling operations as a result of low natural gas prices.

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.

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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 March 31,
	2013		2012
Production:
Natural gas (MMcf)	2,699		2,237
Condensate and oil (MBbl)	78		26
NGLs (MBbl)	80		47
Total production (MMcfe)	3,646		2,678
Daily Production:
Natural gas (MMcf/d)	30.0		24.6
Condensate and oil (MBbl/d)	0.9		0.3
NGLs (MBbl/d)	0.9		0.5
Total daily production (MMcfe/d)	40.5		29.4
Average sales price per unit:
Natural gas per Mcf, excluding impact of realized hedging activities	$	2.82	$	1.96
Natural gas per Mcf, including impact of realized hedging activities	4.16		3.09
Condensate and oil per Bbl, excluding impact of realized hedging activities	67.86		74.74
Condensate and oil per Bbl, including impact of realized hedging activities	78.66		71.76
NGLs per Bbl, excluding impact of realized hedging activities	29.78		39.80
NGLs per Bbl, including impact of realized hedging activities	44.32		39.76
Average sales price per Mcfe, excluding impact of realized hedging activities	$	4.19	$	3.08
Average sales price per Mcfe, including impact of realized hedging activities	5.73		3.99
Selected operating expenses (in thousands):
Production taxes	$	643	$	453
Lease operating expenses	1,837		2,416
Transportation, treating and gathering	1,164		1,179
Depreciation, depletion and amortization	5,365		5,653
General and administrative expense	3,002		3,161
Selected operating expenses per Mcfe:
Production taxes	$	0.18	$	0.17
Lease operating expenses	0.50		0.90
Transportation, treating and gathering	0.32		0.44
Depreciation, depletion and amortization	1.47		2.11
General and administrative expense	0.82		1.18
Production costs (1)	0.77		1.30

 _________________________________

(1) Production costs include lease operating expenses, insurance, gathering and workover expense and excludes ad valorem and severance taxes.

Three Months Ended March 31, 2013 compared to the Three Months Ended March 31, 2012

Revenues. Total natural gas, condensate, oil and NGLs revenues were $20.9 million for the three months ended March 31, 2013, up96% from $10.7 million for the three months ended March 31, 2012. The increase in revenues was the result of a 36%increase in production and a 44%increase in weighted average realized prices. Average daily production on an equivalent basis was 40.5 MMcfe/d for the three months ended March 31, 2013 compared to 29.4 MMcfe/d for the same period in 2012. Condensate, oil and NGLs production represented approximately 26% of total production for the three months ended March 31,

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2013 compared to 16% of total production for the three months ended March 31, 2012, and 24% of total production for the three months ended December 31, 2012.

Liquids revenues (condensate, oil and NGLs) represented approximately 46% of our total natural gas, condensate and oil and NGLs revenues for the three month period ended March 31, 2013 compared to 35% for the three month period ended March 31, 2012. Due to continued lower natural gas prices, we are continuing to focus our drilling activity in the liquids-rich portions of the Marcellus Shale and the Hunton Limestone oil play in Oklahoma. If current trends of natural gas prices relative to condensate, oil and NGLs prices continue, and assuming that we successfully and timely complete our 2013 drilling activity, we expect our liquids revenues to continue to increase as a percentage of total revenues in 2013.

During the three months ended March 31, 2013, we had commodity derivative contracts covering approximately 73% of our natural gas production, which resulted in realized gains of $3.6 million, comprised of $3.6 million in NYMEX hedge gains offset by $25,000 of regional basis losses, and an increase in total price realized from $2.82 per Mcf to $4.16 per Mcf. For additional information regarding our natural gas hedging positions as of March 31, 2013, see Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report. During the three months ended March 31, 2012, the realized effect of hedging on natural gas sales was an increase of $2.5 million in natural gas revenues resulting in an increase in total price realized from $1.96 per Mcf to $3.09 per Mcf. The 2012 realized hedge impact included a benefit of $220,000 of non-cash amortization of prepaid call sale and put purchase premiums and payment of deferred put premiums of $1.1 million.

During the three months ended March 31, 2013, we had commodity derivative contracts covering approximately 36% of our condensate and oil production. The realized effect of hedging on condensate and oil sales during the three months ended March 31, 2013 was an increase of $841,000 in condensate and oil revenues resulting in an increase in total price realized from $67.86 per Bbl to $78.66 per Bbl. For additional information regarding our oil hedging positions as of March 31, 2013, see Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report. During the three months ended March 31, 2012, the realized effect of hedging on condensate and oil sales was a decrease of $78,000 in condensate and oil revenues which resulted in a decrease in total price realized from $74.74 per Bbl to $71.76 per Bbl. For both periods, we designated 50% of our current crude hedges as price protection for our NGLs production.

During the three months ended March 31, 2013, we had commodity derivative contracts covering approximately 70% of our NGLs production. The realized effect of hedging on NGLs sales during the three months ended March 31, 2013 was an increase of $1.2 million in NGLs revenues resulting in an increase in total price realized from $29.78 per Bbl to $44.32 per Bbl. For additional information regarding our NGLs hedging positions as of March 31, 2013, see Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report. During the three months ended March 31, 2012, the realized effect of hedging on NGLs sales was a decrease of $2,000 in NGLs revenues which resulted in a decrease in total price realized from $39.80 per Bbl to $39.76 per Bbl.

Unrealized hedge loss was $9.6 million for the three months ended March 31, 2013 compared to $1.5 million for the three months ended March 31, 2012. The increase in unrealized hedge loss is the result of higher future NYMEX natural gas prices and future oil and NGLs prices coupled with the addition of new future hedges.

Production taxes. We reported production taxes of $643,000 for the three months ended March 31, 2013 compared to $453,000 for the three months ended March 31, 2012. The increase in production taxes primarily resulted from higher revenues in West Virginia due to increased natural gas, condensate, oil and NGLs production.

Lease operating expenses. We reported lease operating expenses of $1.8 million for the three months ended March 31, 2013 compared to $2.4 million for the three months ended March 31, 2012. Our total LOE was $0.50 per Mcfe for the three months endedMarch 31, 2013 compared to $0.90 per Mcfe for the same period in 2012. The decrease in our lease operating expenses (“LOE”) was primarily due to a $669,000 decrease in controllable LOE. Of this decrease, $325,000 is due to the assignment of our Powder River Basin properties to the operator on May 3, 2012 and $457,000 is due to reduced activity in East Texas for the three months ended March 31, 2013 compared to the same period in 2012, partially offset by increases in Marcellus Shale and Mid-Continent LOE as a result of increased activity.

Transportation, treating and gathering. We reported transportation expenses of $1.2 million for the three months ended March 31, 2013 and 2012, of which $927,000 and $930,000, respectively, related to our Hilltop operations in East Texas. The current quarter includes $569,000 of minimum volume requirement charges under our Hilltop gas gathering agreement compared to $465,000 of such charges in the same quarter of 2012. Such charges resulted from actual production volumes being less than minimum contractual volume requirements. Upon closing of the East Texas Sale Agreement, the buyer will assume the minimum volume requirements.

Depreciation, depletion and amortization. We reported depreciation, depletion and amortization (“DD&A”) expense of $5.4 million for the three months ended March 31, 2013down from $5.7 million for the three months ended March 31, 2012. The decrease in DD&A expense was the result of a 30% decrease in the DD&A rate per Mcfe offset by a 36% increase in

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production. The DD&A rate for the three months ended March 31, 2013 was $1.47 per Mcfe compared to $2.11 per Mcfe for the same period in 2012. The decrease in the rate is primarily due to lower proved costs as result of $150.8 million of ceiling impairment charges recorded during the second and third quarters of 2012 combined with increased total proved reserves.

General and administrative expense. We reported general and administrative expenses of $3.0 million for the three months ended March 31, 2013, down from $3.2 million for the three months ended March 31, 2012. Non-cash stock-based compensation expense, which is included in general and administrative expense, decreased $69,000 to $823,000 for the three months ended March 31, 2013 compared to the three months ended March 31, 2012. Excluding stock-based compensation expense, general and administrative expense decreased $90,000 to $2.2 million for the three months ended March 31, 2013 compared to the three months ended March 31, 2012. This decrease is primarily due to lower professional fees partially offset by an increase in personnel costs.

Litigation settlement expense. We reported litigation settlement expense of $1.0 million for the three months ended March 31, 2013, resulting from our settlement with Chesapeake on March 28, 2013, compared to $1.3 million for the three months ended March 31, 2012 resulting from our settlement with Navasota Resources L.P. For additional information regarding the settlement of the Chesapeake matter, see Note 13, “Commitments and Contingencies” to our condensed consolidated financial statements included in this report.

Interest expense. We reported interest expense of $609,000 for the three months ended March 31, 2013 compared to $27,000 for the three months ended March 31, 2012. The increase in interest expense is directly related to the increase in long-term debt from 2012 to 2013 and lower capitalized interest due to impairment of East Texas unproven property during 2012.

Dividends on Preferred Stock. We reported dividend expense on our Series A Preferred Stock of $2.1 million for the three months ended March 31, 2013 compared to $1.2 million for the three months ended March 31, 2012. The Series A Preferred Stock had a stated value of approximately $76.6 million and $58.2 million at March 31, 2013 and 2012, respectively, and carries a cumulative dividend rate of 8.625% per annum. The increase in dividend expense on Series A Preferred Stock is due to 3,951,254 shares of Series A Preferred Stock outstanding at March 31, 2013 compared to 2,981,937 shares at March 31, 2012. Based on the number of shares of Series A Preferred Stock outstanding at March 31, 2013, our stated preferred dividend expense is $2.1 million per quarter, which is subject to being declared and paid monthly.

Liquidity and Capital Resources

Overview. Our primary sources of liquidity and capital resources are internally generated cash flows from operating activities, availability under the Revolving Credit Facility, asset sales and access to capital markets, to the extent available. We continually evaluate our capital needs and compare them to our capital resources and ability to raise funds in the financial markets. We may adjust capital expenditures in response to changes in natural gas, condensate, oil and NGLs prices, drilling results and cash flow.

For the three months ended March 31, 2013, we reported cash flows provided by operating activities of $10.9 million, net cash used in investing activities, primarily for the development and purchase of natural gas and oil properties, including a $7.4 million deposit for the purchase of the Chesapeake assets, of $27.9 million and net cash provided by financing activities of $15.2 million, consisting of $17.0 million of net borrowings under our Revolving Credit Facility, less $1.4 million of dividends paid on the preferred stock. As a result of these activities, our cash and cash equivalents balance decreased by $1.8 million, resulting in a cash and cash equivalents balance of $7.1 million at March 31, 2013.

At March 31, 2013, we had a net working capital deficit of approximately $51.4 million, including $33.6 million of advances from non-operators. At March 31, 2013, availability under our Revolving Credit Facility was $45.0 million.

Future capital and other expenditure requirements. Capital expenditures for the remainder of 2013, excluding acquisitions, are projected to be approximately $56.3 million. In the Marcellus Shale and Mid-Continent, we expect to spend $35.8 million and $17.7 million, respectively, for drilling, completion, infrastructure, lease acquisition and seismic costs. In addition, we have allocated $2.8 million for capitalized interest and other costs. In addition, 2013 capital expenditures related to drilling on the Mid-Continent assets to be acquired from Chesapeake are expected to be $10.7 million net. On March 28, 2013, we entered into (i) the Chesapeake Purchase Agreement to acquire approximately 157,000 net acres of oil and gas leasehold interests in Oklahoma, including production from interests in 176 producing wells in Oklahoma, for a cash purchase price of approximately $74.2 million, subject to customary adjustments and (ii) the Chesapeake Settlement Agreement to effect a mutual full and unconditional release and settlement of all claims made in the lawsuit filed by Chesapeake, pursuant to which the Company will pay Chesapeake approximately $10.8 million in cash, approximately $9.8 million of which will be paid for the repurchase of 6,781,768 outstanding common shares of Parent currently held by Chesapeake. Subsequent to the quarter end, on April 19, 2013, we entered into the East Texas Sale agreement to divest of approximately 31,800 gross (16,300 net) acres of leasehold interests in the Hilltop area of East Texas, including production from interests in producing wells, effective January 1, 2013, for approximately $46.0 million, subject to customary adjustments. We plan to fund our remaining 2013

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capital budget and the Chesapeake acquisition, share repurchase and settlement through existing cash balances, internally generated cash flow from operating activities, borrowings under the Revolving Credit Facility, the issuance of debt securities or preferred stock and proceeds from the divestiture of our East Texas assets. 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, condensate, oil and NGLs prices, costs of drilling and completion and leasehold acquisitions, drilling results, and changes in the borrowing base under the Revolving Credit Facility. We operate approximately 73% of our remaining budgeted 2013 capital expenditures, including expenditures related to drilling on the Mid-Continent assets to be acquired from Chesapeake, and thus, we could reduce a significant portion of 2013 capital expenditures if necessary to better match available capital resources.

Operating Cash Flow and 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, condensate, oil and NGLs. 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, oil and NGLs 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, condensate, oil and NGLs 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. For additional information regarding our hedging activities, see Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report.

At March 31, 2013, the estimated fair value of all of our commodity derivative instruments was a net liability of $3.1 million, comprised of current and non-current assets and liabilities. By removing the price volatility from a portion of our natural gas, condensate, oil and NGLs sales for 2013 through 2017, 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 March 31, 2013, 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 March 31, 2013 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. Effective March 31, 2013, the borrowing base under the Revolving Credit Facility was increased from $125.0 million to $160.0 million. At March 31, 2013, we had $115.0 million outstanding under our Revolving Credit Facility, compared to our December 31, 2012 outstanding balance of $98.0 million. The increase in our long-term debt balance is primarily associated with expenditures for the development of natural gas and oil properties paid during the three months ended March 31, 2013 of $41.3 million, including a $7.4 million deposit for the purchase of the Chesapeake assets. Borrowing base redeterminations are scheduled semi-annually with the next redetermination scheduled for November 2013. However, we and the lenders may each request one additional unscheduled redetermination annually.

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 May 1, 2013, our availability under our Revolving Credit Facility was $45.0 million.

At March 31, 2013, 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 March 31, 2013, 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.

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We are party to various litigation matters and administrative claims arising out of the normal course of business. Although the ultimate outcome of each of these matters cannot be absolutely determined and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters, management does not believe any such matters will have a material adverse effect on our financial position, results of operations or cash flows. A discussion of current legal proceedings is set forth in Part. I Item 1. “Financial Statements, Note 13 – 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 2012 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, condensate, oil and NGLs 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, condensate, oil and NGLs in the region produced. Prices received for natural gas, condensate, oil and NGLs 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 months endedMarch 31, 2013, a 10% change in the prices received for natural gas, condensate, oil and NGLs production would have had an approximate $1.5 million impact 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 March 31, 2013, we had $115.0 million outstanding under the Revolving Credit Facility. Based on the amount outstanding under our Revolving Credit Facility at March 31, 2013, a one percentage point change in the interest rate would have had a $287,000 impact on our interest expense. We currently do not use interest rate derivatives to mitigate our exposure to the volatility in interest rates, including under the Revolving Credit Facility, as this risk is minimal.

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 March 31, 2013. 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 March 31, 2013, 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

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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 March 31, 2013 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 13 – 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 months endedMarch 31, 2013 does not materially differ from that set out under Part I, Item 1A. “Risk Factors” in our 2012 Form 10-K. You should carefully consider the risk factors and other information discussed in our 2012 Form 10-K, as well as the information provided in this report. These risks are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, operating results and cash flows.

The representation, warranties and indemnifications of Chesapeake contained in the Chesapeake Purchase Agreement are limited; as a result, the assumptions on which our estimates of future results of the acquired assets have been based may prove to be incorrect in a number of material ways, resulting in our not realizing the expected benefits of the acquisition. The acquisition could also expose us to additional unknown and contingent liabilities.

The representations and warranties of Chesapeake contained in the Chesapeake Purchase Agreement are limited. In addition, the agreement provides limited indemnities. As a result, the assumptions on which our estimates of future results of the acquired assets have been based may prove to be incorrect in a number of material ways, resulting in our not realizing our expected benefits of the acquisition, including anticipated increased cash flow.

The acquisition could expose us to additional unknown and contingent liabilities. We have performed a certain level of diligence in connection with the acquisition and have attempted to verify the representations made by Chesapeake, but there may be unknown and contingent liabilities related to the acquired assets of which we are unaware. Chesapeake has agreed to indemnify us for losses or claims relating to the acquired assets and otherwise subject to the limitations described in the Chesapeake Purchase Agreement. We could be liable for unknown obligations relating to the acquired assets for which indemnification is not available, which could materially adversely affect our business, results of operations and cash flow.

The closing of the Chesapeake transaction is not subject to a financing condition. We may be required to fund a portion of the purchase price with borrowings under our Revolving Credit Facility.

The closing of the Chesapeake transaction is not subject to a financing condition. There is no assurance that we will be able to arrange new financing to fund the transactions. We may be required to fund a portion of the purchase price with borrowings under our Revolving Credit Facility, which may require a waiver from the lenders under our Revolving Credit Facility. We cannot assure you that the lenders under our Revolving Credit Facility will grant such waiver.

We may not complete the East Texas Divestiture.

The closing of the Chesapeake transaction is not subject to a condition that we successfully complete the sale of our East Texas assets. There can be no assurance that the sale of our East Texas assets will be completed or, if completed, that it will be completed on the terms described elsewhere in this Quarterly Report on Form 10-Q. If we are unable to successfully complete the sale of our East Texas assets, we will be unable to realize the anticipated uses of proceeds from the sale and the improved liquidity position from the transaction.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosure

Not applicable.

Item 5. Other Information

None.

38

Item 6. Exhibits

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

Exhibit Number	Description
2.1*	Purchase and Sale Agreement, dated March 28, 2013, by and among Chesapeake Exploration, L.L.C., Arcadia Resources, L.P., Jamestown Resources, L.L.C., Larchmont Resources, L.L.C and Gastar Exploration USA, Inc.
2.2*	Purchase and Sale Agreement, dated April 19, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc.
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).
10.1†	Form of the Final Settlement Agreement between Chesapeake Exploration, L.L.C., Chesapeake Energy Corporation, Gastar Exploration Ltd., Gastar Exploration Texas, LP and Gastar Exploration Texas, LLC Effective March 28, 2013.
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

39

Exhibit Number	Description
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

____________________________________

* Pursuant to Item 601(b)(2) of Regulation S-K, the schedules and similar attachments Exhibit 2.1 and Exhibit 2.2 have not been filed herewith. The registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.

† Filed herewith.

†† Furnished herewith.

40

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:	May 2, 2013	By:	/S/ J. RUSSELL PORTER
			J. Russell Porter
			President and Chief Executive Officer
			(Duly authorized officer and principal executive officer)

Date:	May 2, 2013	By:	/S/ MICHAEL A. GERLICH
			Michael A. Gerlich
			Vice President and Chief Financial Officer
			(Duly authorized officer and principal financial and accounting officer)

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

		GASTAR EXPLORATION USA, INC.
Date:	May 2, 2013	By:	/S/ J. RUSSELL PORTER
			J. Russell Porter
			President
			(Duly authorized officer and principal executive officer)

Date:	May 2, 2013	By:	/S/ MICHAEL A. GERLICH
			Michael A. Gerlich
			Secretary and Treasurer
			(Duly authorized officer and principal financial and accounting officer)

41

EXHIBIT INDEX

Exhibit Number	Description
2.1*	Purchase and Sale Agreement, dated March 28, 2013, by and among Chesapeake Exploration, L.L.C., Arcadia Resources, L.P., Jamestown Resources, L.L.C., Larchmont Resources, L.L.C and Gastar Exploration USA, Inc.
2.2*	Purchase and Sale Agreement, dated April 19, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc.
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).
10.1†	Form of the Final Settlement Agreement between Chesapeake Exploration, L.L.C., Chesapeake Energy Corporation, Gastar Exploration Ltd., Gastar Exploration Texas, LP and Gastar Exploration Texas, LLC Effective March 28, 2013.
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

42

Exhibit Number	Description
101.DEF††	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB††	XBRL Taxonomy Extension Label Linkbase Document
101.PRE††	XBRL Taxonomy Extension Presentation Linkbase Document

___________________________________

* Pursuant to Item 601(b)(2) of Regulation S-K, the schedules and similar attachments Exhibit 2.1 and Exhibit 2.2 have not been filed herewith. The registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.

† Filed herewith.

†† Furnished herewith.

43