Edgar Filing: GASTAR EXPLORATION LTD

GST-9.30.2013-10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________________________________________

FORM 10-Q

____________________________________________________



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

FOR THE QUARTERLY PERIOD ENDED September 30, 2013



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 November 1, 2013 was



Gastar Exploration Ltd.	61,134,950	shares of common stock
Gastar Exploration USA, Inc.	750	shares of common stock

Table of Contents

GASTAR EXPLORATION LTD. AND

GASTAR EXPLORATION USA, INC.

QUARTERLY REPORT ON FORM 10-Q

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2013

TABLE OF CONTENTS



		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements	4
	Gastar Exploration Ltd. Condensed Consolidated Balance Sheets as of September 30, 2013 (unaudited) and December 31, 2012	4
	Gastar Exploration Ltd. Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2013 and 2012 (unaudited)	5
	Gastar Exploration Ltd. Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012 (unaudited)	6
	Gastar Exploration USA, Inc. Condensed Consolidated Balance Sheets as of September 30, 2013 (unaudited) and December 31, 2012	7
	Gastar Exploration USA, Inc. Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2013 and 2012 (unaudited)	8
	Gastar Exploration USA, Inc. Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 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	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4.	Controls and Procedures	44
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 3.	Defaults Upon Senior Securities	47
Item 4.	Mine Safety Disclosure	47
Item 5.	Other Information	47
Item 6.	Exhibits	47
SIGNATURES		50

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.

Table of Contents

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

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30, 2013			December 31, 2012
	(Unaudited)
	(in thousands, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	21,375		$	8,901
Accounts receivable, net of allowance for doubtful accounts of $514 and $546, respectively	10,697			9,540
Commodity derivative contracts	2,259			7,799
Prepaid expenses	616			1,097
Total current assets	34,947			27,337
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, excluded from amortization	102,338			67,892
Proved properties	769,054			671,193
Total natural gas and oil properties	871,392			739,085
Furniture and equipment	2,409			1,925
Total property, plant and equipment	873,801			741,010
Accumulated depreciation, depletion and amortization	(506,187		)	(484,759		)
Total property, plant and equipment, net	367,614			256,251
OTHER ASSETS:
Commodity derivative contracts	7,399			1,369
Deferred charges, net	2,133			836
Advances to operators and other assets	12,311			4,275
Total other assets	21,843			6,480
TOTAL ASSETS	$	424,404		$	290,068
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	5,611		$	23,863
Revenue payable	12,063			8,801
Accrued interest	6,469			151
Accrued drilling and operating costs	2,727			3,907
Advances from non-operators	12,951			17,540
Commodity derivative contracts	794			1,399
Commodity derivative premium payable	1,819			—
Asset retirement obligation	750			358
Other accrued liabilities	8,319			1,493
Total current liabilities	51,503			57,512
LONG-TERM LIABILITIES:
Long-term debt	194,830			98,000
Commodity derivative contracts	—			1,304
Commodity derivative premium payable	7,651			—
Asset retirement obligation	8,006			6,605
Other long-term liabilities	—			111
Total long-term liabilities	210,487			106,020
Commitments and contingencies (Note 13)
SHAREHOLDERS' EQUITY:
Common stock, no par value; unlimited shares authorized; 61,134,950 and 66,432,609 shares issued and outstanding at September 30, 2013 and December 31, 2012, respectively	306,593			316,346
Additional paid-in capital	30,526			28,336
Accumulated deficit	(251,479		)	(294,787		)
Total shareholders' equity	85,640			49,895
Non-controlling interest:
Preferred stock of subsidiary, aggregate liquidation preference $98,954 and $98,781 at September 30, 2013 and December 31, 2012, respectively	76,774			76,641
Total equity	162,414			126,536
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	424,404		$	290,068

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

Table of Contents

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands, except share and per share data)
REVENUES:
Natural gas	$	11,396		$	8,906		$	34,673		$	22,499
Condensate and oil	8,680			3,457			22,823			7,748
NGLs	3,768			2,483			10,690			6,394
Total natural gas, condensate, oil and NGLs revenues	23,844			14,846			68,186			36,641
Unrealized hedge loss	(5,004		)	(5,403		)	(7,156		)	(4,123		)
Total revenues	18,840			9,443			61,030			32,518
EXPENSES:
Production taxes	1,319			560			3,112			1,494
Lease operating expenses	2,190			780			6,196			4,754
Transportation, treating and gathering	1,098			1,305			3,386			3,715
Depreciation, depletion and amortization	8,467			7,135			21,428			19,744
Impairment of natural gas and oil properties	—			78,054			—			150,787
Accretion of asset retirement obligation	142			101			358			284
General and administrative expense	3,998			2,951			11,964			9,263
Litigation settlement expense	—			—			1,000			1,250
Total expenses	17,214			90,886			47,444			191,291
INCOME (LOSS) FROM OPERATIONS	1,626			(81,443		)	13,586			(158,773		)
OTHER INCOME (EXPENSE):
Gain on acquisition of assets at fair value	—			—			43,712			—
Interest expense	(3,439		)	(30		)	(7,593		)	(86		)
Investment income and other	8			2			16			6
Foreign transaction loss	(3		)	(2		)	(15		)	(2		)
INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES	(1,808		)	(81,473		)	49,706			(158,855		)
Provision for income taxes	—			—			—			—
NET INCOME (LOSS)	(1,808		)	(81,473		)	49,706			(158,855		)
Dividend on preferred stock attributable to non-controlling interest	(2,134		)	(1,984		)	(6,398		)	(4,947		)
NET INCOME (LOSS) ATTRIBUTABLE TO GASTAR EXPLORATION LTD.	$	(3,942	)	$	(83,457	)	$	43,308		$	(163,802	)
NET INCOME (LOSS) PER COMMON SHARE ATTRIBUTABLE TO GASTAR EXPLORATION LTD. COMMON SHAREHOLDERS:
Basic	$	(0.07	)	$	(1.31	)	$	0.71		$	(2.58	)
Diluted	$	(0.07	)	$	(1.31	)	$	0.68		$	(2.58	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic	57,359,357			63,601,645			61,159,117			63,494,224
Diluted	57,359,357			63,601,645			63,971,038			63,494,224

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

Table of Contents

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	For the Nine Months Ended September 30,
	2013			2012
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	49,706		$	(158,855	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	21,428			19,744
Impairment of natural gas and oil properties	—			150,787
Stock-based compensation	2,540			2,575
Unrealized hedge loss	7,156			4,123
Realized loss (gain) on derivative contracts	18			(662		)
Amortization of deferred financing costs	1,790			157
Accretion of asset retirement obligation	358			284
Gain on acquisition of assets at fair value	(43,712		)	—
Changes in operating assets and liabilities:
Accounts receivable	(1,259		)	2,429
Prepaid expenses	481			345
Accounts payable and accrued liabilities	733			129
Net cash provided by operating activities	39,239			21,056
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of natural gas and oil properties	(77,813		)	(100,606		)
Acquisition of natural gas and oil properties	(78,809		)	—
Proceeds from sale of natural gas and oil properties	70,708			—
Advances to operators	(13,104		)	(4,282		)
Use of advances from non-operators	(4,589		)	(1,085		)
Purchase of furniture and equipment	(484		)	(235		)
Net cash used in investing activities	(104,091		)	(106,208		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility	19,000			70,000
Repayment of revolving credit facility	(117,000		)	(30,000		)
Proceeds from issuance of senior secured notes, net of discount	194,500			—
Repurchase of outstanding common shares	(9,753		)	—
Proceeds from issuance of preferred stock, net of issuance costs	133			49,169
Dividend on preferred stock attributable to non-controlling interest	(6,398		)	(4,947		)
Deferred financing charges	(2,807		)	(332		)
Other	(349		)	(282		)
Net cash provided by financing activities	77,326			83,608
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	12,474			(1,544		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	8,901			10,647
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	21,375		$	9,103

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

Table of Contents

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30, 2013			December 31, 2012
	(Unaudited)
	(in thousands, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	21,362		$	8,892
Accounts receivable, net of allowance for doubtful accounts of $514 and $546, respectively	10,696			9,539
Commodity derivative contracts	2,259			7,799
Prepaid expenses	587			919
Total current assets	34,904			27,149
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, excluded from amortization	102,338			67,892
Proved properties	769,046			671,185
Total natural gas and oil properties	871,384			739,077
Furniture and equipment	2,409			1,925
Total property, plant and equipment	873,793			741,002
Accumulated depreciation, depletion and amortization	(506,180		)	(484,752		)
Total property, plant and equipment, net	367,613			256,250
OTHER ASSETS:
Commodity derivative contracts	7,399			1,369
Deferred charges, net	2,133			836
Advances to operators and other assets	12,311			4,275
Total other assets	21,843			6,480
TOTAL ASSETS	$	424,360		$	289,879
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	5,611		$	23,863
Revenue payable	12,063			8,801
Accrued interest	6,469			151
Accrued drilling and operating costs	2,727			3,907
Advances from non-operators	12,951			17,540
Commodity derivative contracts	794			1,399
Commodity derivative premium payable	1,819			—
Asset retirement obligation	750			358
Other accrued liabilities	7,974			1,480
Total current liabilities	51,158			57,499
LONG-TERM LIABILITIES:
Long-term debt	194,830			98,000
Commodity derivative contracts	—			1,304
Commodity derivative premium payable	7,651			—
Asset retirement obligation	7,999			6,598
Due to parent	34,805			30,903
Other long-term liabilities	—			111
Total long-term liabilities	245,285			136,916
Commitments and contingencies (Note 13)
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value; 10,000,000 shares authorized; 3,958,160 and 3,951,254 shares issued and outstanding at September 30, 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	225,431			237,431
Additional paid-in capital	76,734			76,601
Accumulated deficit	(174,288		)	(218,608		)
Total stockholders' equity	127,917			95,464
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	424,360		$	289,879

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

Table of Contents

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands, except share and per share data)
REVENUES:
Natural gas	$	11,396		$	8,906		$	34,673		$	22,499
Condensate and oil	8,680			3,457			22,823			7,748
NGLs	3,768			2,483			10,690			6,394
Total natural gas, condensate, oil and NGLs revenues	23,844			14,846			68,186			36,641
Unrealized hedge loss	(5,004		)	(5,403		)	(7,156		)	(4,123		)
Total revenues	18,840			9,443			61,030			32,518
EXPENSES:
Production taxes	1,319			560			3,112			1,494
Lease operating expenses	2,190			780			6,196			4,754
Transportation, treating and gathering	1,098			1,305			3,386			3,715
Depreciation, depletion and amortization	8,467			7,135			21,428			19,744
Impairment of natural gas and oil properties	—			78,054			—			150,787
Accretion of asset retirement obligation	142			101			358			284
General and administrative expense	3,538			2,481			10,935			8,105
Litigation settlement expense	—			—			1,000			1,250
Total expenses	16,754			90,416			46,415			190,133
INCOME (LOSS) FROM OPERATIONS	2,086			(80,973		)	14,615			(157,615		)
OTHER INCOME (EXPENSE):
Gain on acquisition of assets at fair value	—			—			43,712			—
Interest expense	(3,439		)	(30		)	(7,593		)	(87		)
Investment income and other	(7		)	(5		)	(5		)	(4		)
Foreign transaction (loss) gain	(3		)	1			(11		)	2
INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES	(1,363		)	(81,007		)	50,718			(157,704		)
Provision for income taxes	—			—			—			—
NET INCOME (LOSS)	(1,363		)	(81,007		)	50,718			(157,704		)
Dividend on preferred stock	(2,134		)	(1,984		)	(6,398		)	(4,947		)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDER	$	(3,497	)	$	(82,991	)	$	44,320		$	(162,651	)

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

Table of Contents

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	For the Nine Months Ended September 30,
	2013			2012
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	50,718		$	(157,704	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	21,428			19,744
Impairment of natural gas and oil properties	—			150,787
Stock-based compensation	2,540			2,575
Unrealized hedge loss	7,156			4,123
Realized loss (gain) on derivative contracts	18			(662		)
Amortization of deferred financing costs	1,790			157
Accretion of asset retirement obligation	358			284
Gain on acquisition of assets at fair value	(43,712		)	—
Changes in operating assets and liabilities:
Accounts receivable	(1,259		)	2,427
Prepaid expenses	332			215
Accounts payable and accrued liabilities	421			(43		)
Net cash provided by operating activities	39,790			21,903
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of natural gas and oil properties	(77,813		)	(100,606		)
Acquisition of natural gas and oil properties	(78,809		)	—
Proceeds from sale of natural gas and oil properties	70,708			—
Advances to operators	(13,104		)	(4,282		)
Use of advances from non-operators	(4,589		)	(1,085		)
Purchase of furniture and equipment	(484		)	(235		)
Net cash used in investing activities	(104,091		)	(106,208		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility	19,000			70,000
Repayment of revolving credit facility	(117,000		)	(30,000		)
Proceeds from issuance of senior secured notes, net of discounts	194,500			—
Proceeds from issuance of preferred stock, net of issuance costs	133			49,169
Dividend on preferred stock	(6,398		)	(4,947		)
Deferred financing charges	(2,807		)	(332		)
Distribution to Parent, net	(10,657		)	(1,196		)
Other	—			25
Net cash provided by financing activities	76,771			82,719
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	12,470			(1,586		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	8,892			10,595
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	21,362		$	9,009

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

Table of Contents

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. The Company sold substantially all of its East Texas assets on October 2, 2013.

On August 1, 2013, the shareholders of Gastar Exploration Ltd. voted to approve a special resolution approving a plan of arrangement (as amended, the “Arrangement”) pursuant to which Gastar Exploration Ltd. would be continued as if it had been incorporated under the laws of the State of Delaware (the “Delaware Migration”). On August 2, 2013, Gastar Exploration Ltd. obtained a Final Order from the Court of the Queen's Bench of Alberta, as amended on September 17, 2013 and October 28, 2013, approving the Arrangement. Gastar Exploration Ltd. expects to complete the Delaware Migration in the fourth quarter of 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 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 (as amended, the “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. No material item included in those notes has 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 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.

Table of Contents

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

The results of operations for the three and nine months ended September 30, 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 and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these condensed consolidated financial statements, as appropriate.

Recent Accounting Developments

The following recently issued accounting pronouncement may impact the Company in future periods:

Income Taxes. In July 2013, the FASB issued an amendment to previously issued guidance regarding the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. The amendment requires that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward, except as follows. To the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position or the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The assessment of whether a deferred tax asset is available is based on the unrecognized tax benefit and deferred tax asset that exist at the reporting date and should be made presuming disallowance of the tax position at the reporting date. This amendment does not require new recurring disclosures. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. Earlier application is permitted. The Company is currently evaluating the provisions of this amendment.


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, as well as the acquisition of properties in Oklahoma. The Company sold substantially all of its East Texas assets on October 2, 2013.

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



	September 30, 2013		December 31, 2012
	(in thousands)
Unproved properties, excluded from amortization:
Drilling in progress costs	$	8,821	$	1,902
Acreage acquisition costs	88,033		62,395
Capitalized interest	5,484		3,595
Total unproved properties excluded from amortization	$	102,338	$	67,892

For the three and nine months ended September 30, 2013, management's evaluation of unproved properties resulted in an impairment. Due to continued lower natural gas prices for dry gas and no current plans to drill or extend leases in Marcellus East, the Company reclassified $98,000 and $8.0 million of unproved properties to proved properties for the three and nine months ended September 30, 2013, respectively, related to acreage in Marcellus East. For the nine months ended September 30, 2012, management's evaluation of unproved properties resulted in an impairment and the Company reclassified $19.1 million of unproved properties to proved properties due to a decline in natural gas prices and the suspension of drilling activity in East Texas.

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

Table of Contents

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 pricing assumptions utilized in the quarterly ceiling test computations for the respective periods noted before adjustment for basis and quality differentials:



	2013
	Total Impairment		September 30		June 30		March 31
Henry Hub natural gas price (per MMBtu)			$	3.61	$	3.44	$	2.95
West Texas Intermediate oil price (per Bbl)			$	91.69	$	88.13	$	89.17
Impairment recorded (pre-tax) (in thousands)	$	—	$	—	$	—	$	—



	2012
	Total Impairment		September 30		June 30		March 31
Henry Hub natural gas price (per MMBtu)			$	2.83	$	3.15	$	3.73
West Texas Intermediate oil price (per Bbl)			$	91.48	$	92.17	$	94.65
Impairment recorded (pre-tax) (in thousands)	$	150,787	$	78,054	$	72,733	$	—

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 was to acquire approximately 157,000 net acres of Oklahoma oil and gas leasehold interests from the Chesapeake Parties, including production from interests in 206 producing wells located in Oklahoma (the “Chesapeake Assets”). The Chesapeake Purchase Agreement contained customary representations and warranties and covenants, including provisions for indemnification, subject to the limitations described in the Chesapeake Purchase Agreement. On June 7, 2013, the parties to the Chesapeake Purchase Agreement entered into an Amendment to Purchase and Sale Agreement, dated June 7, 2013, in order to revise the description of the properties to be acquired and to evidence the withdrawal of Arcadia Resources, L.P. and Jamestown Resources, L.L.C. from the Chesapeake Purchase Agreement. Pursuant to the Chesapeake Purchase Agreement, as amended, on June 7, 2013, Gastar USA completed the acquisition of the Chesapeake Assets for a final adjusted purchase price of $69.4 million, reflecting adjustment for an acquisition effective date of October 1, 2012.

Upon completion of the initial purchase price allocation, as of June 7, 2013, the Company reviewed and verified its assessment, including the identification and valuation of assets acquired. The Company accounted for the acquisition as a business combination and therefore, recorded the assets acquired at their estimated acquisition date fair values. The Company included $1.4 million of transaction and integration costs associated with the acquisition and expensed these costs as incurred as general and administrative expenses. The Company utilized relevant market assumptions to determine fair value and allocate the purchase price, such as future commodity prices, projections of estimated natural gas and oil reserves, expectations for future development and operating costs, projections of future rates of production, expected recovery rates and market multiples for similar transactions. Many of the assumptions used are unobservable and as such, represent Level 3 inputs under the fair value hierarchy as described in Note 5, “Fair Value Measurements.” The Company's preliminary assessment of the fair value of the Chesapeake Assets resulted in a fair market valuation of $113.5 million. As a result of incorporating the valuation information into the purchase price allocation, a bargain purchase gain of $43.7 million was recognized in the accompanying condensed consolidated statements of operations. The bargain purchase gain was primarily attributable to the non-strategic nature of the divestiture to the seller, coupled with favorable economic trends in the industry and the geographic region in which the Chesapeake Assets are located. The Company believes the estimates used in the fair market valuation and purchase price allocation are reasonable and that the significant effects of the acquisition are properly reflected. However, the estimates are subject to change as additional information becomes available and is assessed by the Company. Changes to the purchase price allocation and any corresponding change to the bargain purchase gain will be adjusted retrospectively to the period of the acquisition.

Table of Contents

Hunton Joint Venture

Effective July 1, 2013, Gastar USA's working interest partner in its original AMI in Oklahoma exercised its rights to acquire approximately 12,800 net acres and certain proved properties that Gastar USA acquired pursuant to the Chesapeake Purchase Agreement for a total payment of $12.1 million, of which $133,000 was deemed to be a reimbursement of transaction and integration costs associated with the acquisition and was recorded as a reduction of the Company's general and administrative expense.

Hunton Divestiture

On July 2, 2013, Gastar USA entered into a purchase and sale agreement with Newfield Exploration Mid-Continent Inc. (“Newfield”), dated July 2, 2013, pursuant to which Newfield acquired approximately 76,000 net acres of oil and gas leasehold interests in Kingfisher and Canadian Counties, Oklahoma from Gastar USA and Gastar USA acquired approximately 2,260 net acres of Oklahoma oil and gas leasehold interests from Newfield. The transaction closed on August 6, 2013 for a net cash purchase price of approximately $54.0 million, adjusted for an acquisition effective date of May 1, 2013. The Company did not record a gain or loss related to the divestiture as it was not significant to the full cost pool.

WEHLU Acquisition

On September 4, 2013, Gastar USA entered into a Purchase and Sale Agreement, dated September 4, 2013, by and among Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P. (the “Lime Rock Parties”) and Gastar USA (the “WEHLU Purchase Agreement”). Pursuant to the WEHLU Purchase Agreement, Gastar USA will acquire a 98.3% working interest (80.5% net revenue interest) in 24,000 net acres of the West Edmond Hunton Lime Unit (“WEHLU”) located in Kingfisher, Logan and Oklahoma Counties, Oklahoma, for a cash purchase price of $187.5 million, subject to, among other customary adjustments, adjustment for an acquisition effective date of August 1, 2013 (the “WEHLU Acquisition”). The Company paid a deposit of $9.4 million, which is currently recorded as an other asset and will be applied to the purchase price at closing. The closing of the WEHLU Acquisition is subject to satisfaction of customary closing conditions and delivery of the total acquisition purchase price. Gastar USA anticipates the WEHLU Acquisition will close in late November 2013.

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, as amended, on October 2, 2013, Cubic Energy acquired 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 net proceeds of approximately $43.9 million, reflecting adjustment for accounting effective date of January 1, 2013 and other customary adjustments and of which $4.7 million was previously received as a deposit and was accounted for in other liabilities at September 30, 2013. The Company will not record a gain or loss related to the divestiture as it was not significant to the full cost pool.

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. As of September 30, 2013, all 57 gross wells were on production as agreed upon.

Table of Contents


4.	Long-Term Debt

Second Amended and Restated Revolving Credit Facility

On June 7, 2013, Gastar USA entered into the Second Amended and Restated Credit Agreement, dated as of June 7, 2013, among Gastar USA, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and Issuing Lender and the lenders named therein (the “New Revolving Credit Facility”). The New Revolving Credit Facility provides an initial borrowing base of $50.0 million, with borrowings bearing interest, at Gastar USA's election, at the reference rate or the Eurodollar rate plus an applicable margin. The reference rate is the greater of (i) the rate of interest publicly announced by the administrative agent or (ii) the federal funds rate plus 50 basis points. The applicable interest rate margin varies from 1.0% to 2.0% in the case of borrowings based on the reference rate and from 2.0% to 3.0% in the case of borrowings based on the Eurodollar rate, depending on the utilization percentage in relation to the borrowing base. An annual commitment fee of 0.5% is payable quarterly on the unutilized balance of the borrowing base. The New Revolving Credit Facility has a scheduled maturity of November 14, 2017.

The New Revolving Credit Facility is guaranteed by all of Gastar USA's current domestic subsidiaries and all future domestic subsidiaries formed during the term of the New 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 New Revolving Credit 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 New Revolving Credit Facility contains various covenants, including among others:


•	Restrictions on liens, incurrence of other indebtedness without lenders' consent and common stock 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, as of the fiscal quarter ending September 30, 2013, of not greater than 4.25 to 1.0, and for each quarter thereafter, 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 of Gastar USA, as defined in the New Revolving Credit Facility.

On July 31, 2013, Gastar USA, together with the parties thereto, entered into the Waiver, Agreement and Amendment No. 1 to Second Amended and Restated Credit Agreement (the “First Amendment”). The First Amendment amended the New Revolving Credit Facility to clarify the current ratio covenant calculation.

On October 18, 2013, Gastar USA, together with the parties thereto, entered into the Agreement and Amendment No. 2 (“Amendment No. 2”) to Second Amended and Restated Credit Agreement, dated as of June 7, 2013. Amendment No. 2 amended the New Revolving Credit Facility to, among other things, (i) increase the aggregate principal amount of 8 5/8% Senior Secured Notes due 2018 permitted to be issued from $200.0 million to $325.0 million, (ii) allow for the issuance by Gastar USA of Series B Preferred Stock and (iii) increase the aggregate amount of cash dividends permitted to be paid to preferred stockholders from $12.5 million to $20.0 million.

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 during any six-month period between scheduled redeterminations. At September 30, 2013, the New Revolving Credit Facility had a borrowing base of $50.0 million, with $0 borrowings outstanding and availability of $50.0 million. The next regularly scheduled redetermination is set for November 2013. Future increases in the borrowing base in excess of the $50.0 million are limited to 17.5% of the increase in adjusted consolidated net tangible assets as defined in the Notes agreement (as discussed below in “Senior Secured Notes”).

At September 30, 2013, Gastar USA was in compliance with all financial covenants under the New Revolving Credit Facility.

Table of Contents

Amended and Restated Revolving Credit Facility

For the period October 28, 2009 through June 6, 2013, Gastar USA, together with the other parties thereto, was subject to an amended and restated credit facility (the “Old Amended Revolving Credit Facility”). The Old Amended Revolving Credit Facility provided for various borrowing base amounts based on an initial borrowing base of $47.5 million and a final borrowing base of $160.0 million effective March 31, 2013. Borrowings bore interest, at Gastar USA’s election, at the prime rate or LIBO rate plus an applicable margin. The applicable interest rate margin varied 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% was payable quarterly based on the unutilized balance of the borrowing base. The Old Amended Revolving Credit Facility had a final scheduled maturity date of September 30, 2015.

The Old Amended Revolving Credit Facility was guaranteed by Parent (as defined in the Old Amended Revolving Credit Facility) and all of Gastar USA’s current domestic subsidiaries and all future domestic subsidiaries formed during the term of the Old Amended Revolving Credit Facility. Borrowings and related guarantees were 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 was 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 Old Amended Revolving Credit Facility contained various covenants, including among others:


•	Restrictions on liens, incurrence of other indebtedness without lenders' consent and other restricted payments including a restriction on the amount of cash dividends to be paid in aggregate on the Gastar USA Series A Preferred Stock each calendar year, subject to certain available commitment thresholds;


•	Limitation of hedging volumes with a final limitation of 100% of the proved developed reserves as reflected in Gastar USA's reserve report using hedging other than floors and protective spreads;


•	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, except for quarters ending on March 31, 2013 through December 31, 2013 whereby the ratio was reduced to 0.6 to 1.0 and making certain changes in the calculation of current liabilities for such periods to exclude advances from non-operators;


•	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 became 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 Old Amended Revolving Credit Facility) of the Parent.

The Old Amended Revolving Credit Facility was amended and restated on June 7, 2013.

Senior Secured Notes

On May 15, 2013, Gastar USA issued $200.0 million aggregate principal amount of its 8 5/8% Senior Secured Notes due 2018 (the “Notes”) under an indenture (the “Indenture”) by and among Gastar USA, the Guarantors named therein (the “Guarantors”), Wells Fargo Bank, National Association, as Trustee (in such capacity, the “Trustee”) and Collateral Agent (in such capacity, the “Collateral Agent”). The Notes bear interest at a rate of 8.625% per year, payable semiannually in arrears on May 15 and November 15 of each year, beginning on November 15, 2013. The Notes will mature on May 15, 2018.

In the event of a change of control, as defined in the Indenture, each holder of the Notes will have the right to require Gastar USA to repurchase all or any part of their notes at an offer price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to the date of purchase.

The Notes are fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by each of Gastar USA's material subsidiaries and certain future domestic subsidiaries (the “Guarantees”). The Notes and Guarantees will rank senior in right of payment to all of Gastar USA's and the Guarantors' future subordinated indebtedness and equal in right of payment to all of Gastar USA's and the Guarantors' existing and future senior indebtedness. The Notes and Guarantees also will be effectively senior to Gastar USA's unsecured indebtedness and effectively subordinated to Gastar USA's and

Table of Contents

Guarantors' under the New Revolving Credit Facility, any other indebtedness secured by a first-priority lien on the same collateral and any other indebtedness secured by assets other than the collateral, in each case to the extent of the value of the assets securing such obligation.

The Indenture contains covenants that, among other things, limit Gastar USA's ability and the ability of its subsidiaries to:


•	Transfer or sell assets or use asset sale proceeds;


•	Pay dividends or make distributions, redeem subordinated debt or make other restricted payments;


•	Make certain investments; incur or guarantee additional debt or issue preferred equity securities;


•	Create or incur certain liens on Gastar USA's assets;


•	Incur dividend or other payment restrictions affecting future restricted subsidiaries;


•	Merge, consolidated or transfer all or substantially all of Gastar USA's assets;


•	Enter into certain transactions with affiliates; and


•	Enter into certain sale and leaseback transactions.

These and other covenants that are contained in the Indenture are subject to important limitations and qualifications that are described in the Indenture.

On May 15, 2013, in connection with the issuance and sale of the Notes, Gastar USA and each of the Guarantors entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with Imperial Capital, LLC, as representative of the initial purchasers. Under the Registration Rights Agreement, Gastar USA has agreed, subject to certain exceptions, to (i) file a registration statement with the SEC with respect to an exchange of the Notes for new notes having terms substantially identical in all material respects to the Notes (except that the exchange notes will not contain terms relating to transfer restrictions), (ii) use its reasonable best efforts to cause the exchange offer registration statement to be declared effective under the Securities Act of 1933, as amended, within 360 days after the issue date of the Notes, (iii) as soon as practicable after the effectiveness of the exchange offer registration statement, offer the exchange notes in exchange for the Notes, and (iv) keep the registered exchange offer open for not less than 30 days (or longer if required by applicable law) after the date of the registered exchange offer is mailed to the holders of the Notes. Gastar USA and the Guarantors also agreed to file a shelf registration statement for the resale of the Notes if an exchange offer cannot be effected within the time period specified above and in other circumstances.

At September 30, 2013, the Notes reflected a balance of $194.8 million, net of unamortized discounts of $5.2 million, on the condensed consolidated balance sheets.


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 or estimated market data based on area transactions, which are Level 3 inputs. For the three and nine months ended September 30, 2013, management's evaluation of unproved properties resulted in an impairment. Due to continued lower natural gas prices for dry gas and no current plans to drill or extend leases in Marcellus East, the Company reclassified $8.0 million of unproved properties to proved properties as of September 30, 2013 related to acreage in Marcellus East. For the nine months ended September 30, 2012, the Company reclassified $19.1 million of unproved properties to proved properties due to a decline in natural gas prices and the suspension of drilling activity in East Texas. As no other fair value measurements are required to be recognized on a non-recurring basis at September 30, 2013, no additional disclosures are provided at September 30, 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 techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active

Table of Contents

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.

Table of Contents

The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2013 and December 31, 2012:



	Fair value as of September 30, 2013
	Level 1		Level 2		Level 3			Total
	(in thousands)
Assets:
Cash and cash equivalents	$	21,375	$	—	$	—		$	21,375
Commodity derivative contracts	—		—		9,658			9,658
Liabilities:
Commodity derivative contracts	—		—		(794		)	(794		)
Total	$	21,375	$	—	$	8,864		$	30,239



	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 and nine months ended September 30, 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 September 30, 2013 and 2012.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands)
Balance at beginning of period	$	4,335		$	15,460		$	6,465		$	15,873
Total gains (losses) (realized or unrealized):
included in earnings	(5,263		)	(2,045		)	(2,229		)	4,594
Purchases	9,470			—			9,470			—
Issuances	—			—			—			—
Settlements (1)	322			(4,314		)	(4,842		)	(11,366		)
Transfers in and (out) of Level 3	—			—			—			—
Balance at end of period	$	8,864		$	9,101		$	8,864		$	9,101
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets still held at September 30, 2013 and 2012	$	(5,004	)	$	(5,403	)	$	(7,156	)	$	(4,123	)

_________________________________


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

At September 30, 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 September 30, 2013 was $199.3 million based on quoted market prices of the senior secured notes (Level 1).

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

Table of Contents

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 September 30, 2013 and 2012, the Company reported unrealized losses of $5.0 million and $5.4 million, respectively, in the condensed consolidated statement of operations related to the change in the fair value of its commodity derivative instruments. For the nine months ended September 30, 2013 and 2012, the Company reported unrealized losses of $7.2 million and a $4.1 million, respectively, in the condensed consolidated statement of operations related to the change in the fair value of its commodity derivative instruments.

As of September 30, 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 MMBtus)
2013	Fixed price swap	5,000	460,000	$	3.65		$	—	$	—	$	—	$	—
2013	Fixed price swap	1,500	138,000	$	3.85		$	—	$	—	$	—	$	—
2013	Fixed price swap	1,500	138,000	4.00			—		—		—		—
2013	Fixed price swap	3,000	276,000	4.06			—		—		—		—
2013	Fixed price swap	2,500	230,000	4.05			—		—		—		—
2013	Fixed price swap	12,663	1,165,000	3.87			—		—		—		—
2013 (1)	Fixed price swap	2,500	77,500	4.05			—		—		—		—
2013 (2)	Protective spread	2,500	152,500	4.05			—		3.79		—		—
2013 (1)	Costless collar	2,500	77,500	—			5.00		—		—		6.45
2013 (2)	Short calls	2,500	152,500	—			—		—		—		6.45
2013	Call spread	2,500	230,000	—			—		—		4.75		5.25
2013	Basis - HSC (4)	4,000	368,000	(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			—		—		—		—
2015	Fixed price swap	3,000	1,095,000	4.00			—		—		—		—
2015	Fixed price swap	2,500	912,500	4.06			—		—		—		—
2016	Fixed price swap	2,000	732,000	4.11			—		—		—		—

_______________________________


(1)	For the period July to October 2013.


(2)	For the period November to December 2013.


(3)	East Houston-Katy - Houston Ship Channel.

Table of Contents

As of September 30, 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	250	23,000	$	103.95	$	—	$	—	$	—
2013	Fixed price swap	850	78,200	99.77		—		—		—
2013	Fixed price swap	400	36,800	94.86		—		—		—
2013	Fixed price swap	611	56,200	92.80		—		—		—
2013 (2)	Put	1,000	31,000	—		103.00		—		—
2014 (3)	Fixed price swap	300	54,300	98.05		—		—		—
2014 (3)	Fixed price swap	550	99,550	95.15		—		—		—
2014 (3)	Put	900	162,900	—		98.00		—		—
2014 (4)	Fixed price swap	200	36,800	93.00		—		—		—
2014 (4)	Fixed price swap	350	64,400	91.55		—		—		—
2014 (4)	Put	750	138,000	—		93.00		—		—
2014	Costless collar	200	73,000	—		98.00		—		98.00
2014	Fixed price swap	500	182,500	91.10		—		—		—
2014	Fixed price swap	270	98,500	90.77		—		—		—
2014 (5)	Put spread	200	24,400	—		93.00		73.00		—
2015	Producer three-way collar	345	126,100	—		85.00		65.00		97.80
2015	Producer three-way collar	400	146,000	—		85.00		70.00		96.50
2015	Put spread	250	91,250	—		89.00		69.00		—
2015 (6)	Producer three-way collar	150	27,150	—		85.00		65.00		96.25
2015 (6)	Put spread	700	126,700	—		90.00		70.00		—
2015 (7)	Producer three-way collar	50	9,200	—		85.00		65.00		96.25
2015 (7)	Put spread	600	110,400	—		87.00		67.00		—
2016	Producer three-way collar	275	100,600	—		85.00		65.00		95.10
2016	Producer three-way collar	330	120,780	—		80.00		65.00		97.35
2016	Put spread	550	201,300	—		85.00		65.00		—
2016	Put spread	300	109,800	—		85.50		65.50		—
2017	Producer three-way collar	242	88,150	—		80.00		60.00		98.70
2017	Producer three-way collar	280	102,200	—		80.00		65.00		97.25
2017	Put spread	500	182,500	—		82.00		62.00		—
2018	Put spread	425	103,275	—		80.00		60.00		—

_______________________________


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


(2)	For the period December 2013.


(3)	For the period January to June 2014.


(4)	For the period July to December 2014.


(5)	For the period September to December 2014.


(6)	For the period January to June 2015.


(7)	For the period July to December 2015.

Table of Contents

As of September 30, 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	150	13,800	$	41.06
2013	Fixed price swap	350	32,200	39.38

As of September 30, 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. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contains credit-risk related contingent features.

In conjunction with certain derivative hedging activity, the Company deferred the payment of certain put premiums for the production month period December 2013 through August 2018. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company will begin amortizing the deferred put premium liabilities in December 2013. The following table provides information regarding the deferred put premium liabilities for the periods indicated:



	September 30, 2013		December 31, 2012

Current commodity derivative premium put payable	$	1,819	$	—
Long-term commodity derivative premium payable	7,651		—
Total unamortized put premium liabilities	$	9,470	$	—

Table of Contents

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	September 30, 2013			December 31, 2012
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Current assets	$	2,259		$	7,799
Commodity derivative contracts	Other assets	7,399			1,369
Commodity derivative contracts	Current liabilities	(794		)	(1,399		)
Commodity derivative contracts	Long-term liabilities	—			(1,304		)
Total derivatives not designated as hedging instruments		$	8,864		$	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	September 30, 2013			September 30, 2012
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Natural gas, condensate, oil and NGLs revenues	$	(259	)	$	3,404
Commodity derivative contracts	Unrealized hedge loss	(5,004		)	(5,403		)
Commodity derivative contracts	Interest expense	—			(46		)
Total		$	(5,263	)	$	(2,045	)



	Amount of Gain (Loss) Recognized in Income on Derivatives
		Amount of Gain (Loss) Recognized in Income on Derivatives For the Nine Months Ended
	Location of Gain (Loss) Recognized in Income on Derivatives	September 30, 2013			September 30, 2012
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Natural gas, condensate, oil and NGLs revenues	$	4,927		$	8,847
Commodity derivative contracts	Unrealized hedge loss	(7,156		)	(4,123		)
Commodity derivative contracts	Interest expense	—			(130		)
Total		$	(2,229	)	$	4,594

Table of Contents


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 September 30, 2013	For the Nine Months Ended September 30, 2013
Other share issuances:
Restricted common shares granted	41,212	2,219,115
Restricted common shares vested	123,250	753,779
Common shares surrendered upon vesting (1)	32,751	222,144
Common shares forfeited	466,535	512,862

__________________


(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 1,931,793 shares available for issuance under the 2006 Plan at September 30, 2013.

Shares Reserved

At September 30, 2013, Parent had 909,100 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 settled and resolved 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 paid Chesapeake approximately $10.8 million in cash, approximately $9.8 million of which was paid for the repurchase of 6,781,768 outstanding common shares of Parent held by Chesapeake Energy Corporation upon the closing of the stock repurchase and settlement on 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 September 30, 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.

On October 25, 2013, Gastar USA filed an Amended and Restated Certificate of Incorporation (the “A&R Certificate”) with the Secretary of State of the State of Delaware. Under the A&R Certificate, the capital stock authorized for issuance was increased from 1,000 shares of common stock, without par value, to 275,000,000 shares of common stock, par value $0.001 per share.

Gastar USA Series A 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

Table of Contents

stock and to determine the designation of any such series. The Gastar USA Board is also authorized to determine or alter the rights, preferences, privileges and restrictions granted to or imposed upon any wholly unissued series of preferred stock and, within the limits and restrictions stated in any resolution or resolutions of the Gastar USA Board originally fixing the number of shares constituting any series, to increase or decrease (but not below the number of shares of any such series outstanding) the number of shares of any series subsequent to the issues shares of that series.

For the nine months ended September 30, 2013, Gastar USA sold 6,906 shares of Series A Preferred Stock under its at the market preferred share purchase agreement (the “ATM Agreement”) for net proceeds of $136,000. At September 30, 2013, there were 3,958,160 total shares of Series A Preferred Stock issued and outstanding. Subsequent to September 30, 2013, Gastar USA did not sell any additional shares of Series A Preferred Stock under the ATM Agreement.

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, 2013 and prior to June 23, 2014	$	25.25
On or after June 23, 2014	$	25.00

Gastar USA pays cumulative dividends on the Series A Preferred Stock at a fixed rate of 8.625% per annum of the $25.00 per share liquidation preference. For the three and nine months ended September 30, 2013, Gastar USA recognized dividend expense of $2.1 million and $6.4 million, respectively.

Gastar USA Series B Preferred Stock

On October 25, 2013, Gastar USA filed the A&R Certificate with the Secretary of State of the State of Delaware. Under the A&R Certificate, the capital stock authorized for issuance was increased from 10,000,000 shares of preferred stock, par value $0.01 per share, to 40,000,000 shares of preferred stock, par value $0.01 per share. On October 31, 2013 Gastar USA filed a Certificate of Designation of Rights and Preferences (the “Certificate of Designation”) to its Certificate of Incorporation for the Series B Preferred Stock with the Secretary of State of the State of Delaware with respect to 10,000,000 shares of Series B Preferred Stock.

On October 29, 2013, Gastar USA announced the pricing of an underwritten public offering of 2,000,000 shares of its 10.75% Series B Cumulative Preferred Stock, par value $0.01 per share and liquidation preference $25.00 per share (the “Series B Preferred Stock”). On November 1, 2013, the underwriters partially exercised their option to purchase additional shares of Series B Preferred Stock and will purchase an additional 140,000 shares of Series B Preferred Stock. The issuance of the 2,140,000 shares of Series B Preferred Stock is expected to close on or about November 5, 2013 with total net proceeds to Gastar USA from the offering expected to be approximately $50.1 million after deducting underwriting commissions and estimated offering expenses.

The Series B Preferred Stock will rank senior to Gastar USA’s common stock and on parity with its 8.625% Series A Cumulative Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series B Preferred Stock will be subordinated to all of Gastar USA’s existing and future debt and all future capital stock designated as senior to the Series B Preferred Stock. The Parent has entered into a guarantee agreement, whereby it will fully and unconditionally guarantee the payment of dividends that have been declared by the board of directors of Gastar USA, amounts payable upon redemption or liquidation, dissolution or winding up, and any other amounts due with respect to the Series B 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.

Table of Contents

Except upon a change in ownership or control, the Series B Preferred Stock may not be redeemed before November 15, 2018, at or after which time it may be redeemed at Gastar USA’s option for $25.00 per share in cash. Following a change in ownership or control, Gastar USA will have the option to redeem the Series B Preferred Stock, in whole but not in part for $25.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), up to, but not including the redemption date. If Gastar USA does not exercise its option to redeem the Series B Preferred Stock upon a change of ownership or control, the holders of the Series B Preferred Stock have the option to convert the shares of Series B Preferred Stock into up to and aggregate of 11.5207 shares of Gastar USA’s common stock per share of Series B Preferred Stock, subject to certain adjustments. If Gastar USA exercises any of its redemption rights relating to shares of Series B Preferred Stock, the holders of Series B Preferred Stock will not have the conversion right described above with respect to the shares of Series B Preferred Stock called for redemption. Notwithstanding any of the foregoing, if a change of ownership or control occurs prior to the consummation of the Reorganization Transactions (as defined in the Certificate of Designation), (i) the holders of Series B Preferred Stock shall not have the conversion right described above and (ii) the dividend rate shall increase to 12.75%.

There is no mandatory redemption of the Series B Preferred Stock.


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:




	PBUs		Fair Value per Unit
Unvested PBUs at December 31, 2012	—		$	—
Granted	1,192,889		1.56
Vested	—		—
Forfeited	(127,155	)	—
Unvested PBUs at September 30, 2013	1,065,734		$	1.56

For the three and nine months ended September 30, 2013, the Company recognized $217,000 and $722,000, respectively, 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:

Table of Contents



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands)
Interest expense:
Cash and accrued	$	4,376		$	549		$	8,238		$	1,272
Amortization of deferred financing costs (1)(2)	340			60			1,790			157
Capitalized interest	(1,277		)	(579		)	(2,435		)	(1,343		)
Total interest expense	$	3,439		$	30		$	7,593		$	86

__________________


(1)	The nine months ended September 30, 2013 includes $1.2 million of deferred financing costs written off as a result of the new Revolving Credit Facility. See Note 4, “Long-Term Debt - Second Amended and Restated Revolving Credit Facility.”


(2)	The three and nine months ended September 30, 2013 includes $221,000 and $330,000, respectively, of debt discount accretion related to the Notes.


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. 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 settled and resolved 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 paid Chesapeake approximately $10.8 million in cash, approximately $9.8 million of which was paid for the repurchase of 6,781,768 outstanding common shares of Parent held by Chesapeake upon the closing of the stock repurchase and settlement on June 7, 2013. See Note 7, “Capital Stock - Shares Owned by Chesapeake Energy Corporation.”

Also on March 28, 2013, the Company entered into the Chesapeake Purchase Agreement, pursuant to which Gastar USA acquired the Chesapeake Assets on June 7, 2013. See Note 3, “Property, Plant and Equipment - Chesapeake Acquisition.”

As of September 30, 2013, Chesapeake Energy Corporation did not own any of Parent’s outstanding common shares.


11.	Income Taxes

For the three and nine months ended September 30, 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 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.

Table of Contents



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013		2012
	(in thousands, except per share and share data)
Net income (loss) attributable to Gastar Exploration Ltd.	$	(3,942	)	$	(83,457	)	$	43,308	$	(163,802	)

Weighted average common shares outstanding - basic	57,359,357			63,601,645			61,159,117		63,494,224
Incremental shares from unvested restricted shares	—			—			2,565,888		—
Incremental shares from outstanding PBUs	—			—			246,033		—
Weighted average common shares outstanding - diluted	57,359,357			63,601,645			63,971,038		63,494,224

Net income (loss) per common share attributable to Gastar Exploration Ltd. Common Shareholders:
Basic	$	(0.07	)	$	(1.31	)	$	0.71	$	(2.58	)
Diluted	$	(0.07	)	$	(1.31	)	$	0.68	$	(2.58	)
Common shares excluded from denominator as anti-dilutive:
Unvested restricted shares	—			1,878,355			41,212		1,654,439
Stock options	756,200			979,725			919,100		926,271
Total	756,200			2,858,080			960,312		2,580,710


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-asserted 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 the new lawsuit, Chesapeake re-asserted 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 alleged 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 established that there was a mutual mistake of fact and a failure of consideration with regard to the November 2005 Agreements. In the alternative, Chesapeake claimed that the Gastar defendants had 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 offered to return Parent's common shares purchased pursuant to the Common Stock Purchase Agreement, and sought restitution from the Gastar defendants of the net amount of approximately $101.4 million, which included 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 failed as a matter of law. Specifically, the Gastar defendants contended in the motion to dismiss that all facts relating to the Navasota claim were fully known to the parties at the time of execution of the November 2005 Agreements, and the parties expressly agreed in the

Table of Contents

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 failed 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 settled and resolved 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 paid Chesapeake approximately $10.8 million in cash, approximately $9.8 million of which was 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 adjusted aggregate cash payment of $80.0 million, comprised of approximately $69.4 million in property acquisition costs (subject to adjustment for an acquisition effective date of October 1, 2012), stock repurchase price of approximately $9.8 million and an additional $1.0 million for litigation settlement occurred on June 7, 2013. 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.

The acquisition transaction closed on June 7, 2013, and the payments described above were made as provided in the Settlement Agreement and the agreement for acquisition of properties from Chesapeake. Thereafter, the parties to the Chesapeake lawsuit filed a stipulation of dismissal of prejudice, and on June 11, 2013, the court entered an order dismissing the case with prejudice.

Gastar Exploration USA, Inc., et al v. Williams Ohio Valley Midstream LLC (American Arbitration Association Matter No. 70-198-Y-00461-13). On July 16, 2013, Gastar USA and two similarly situated co-claimants initiated an arbitration proceeding against Williams Ohio Valley Midstream LLC (“Williams OVM”). The claimants allege that Williams OVM has breached various agreements relating to the gathering, processing and marketing of natural gas, NGLs and condensate produced from properties that are owned in part by Gastar USA in the Marcellus Shale in Marshall and Wetzel Counties, West Virginia, and request that an Arbitration Panel assess an unspecified amount of damages against Williams OVM for, among other claims, failure to timely construct certain gathering and processing facilities, maximize the net value of produced condensation, and fractionate and purchase NGLs as provided in the agreements. On August 7, 2013, Williams OVM filed an answering statement and counterclaim for damages in excess of $612,000 in the arbitration matter. The arbitration has been scheduled for a final hearing in October 2014. Gastar USA intends to vigorously pursue its rights in the arbitration matter against Williams OVM.

Gastar Exploration Ltd vs. U.S. Specialty Ins. Co. and Axis Ins. Co. (Cause No.2010-11236) District Court of Harris County, Texas 190th Judicial District. On February 19, 2010, the Company filed a lawsuit claiming that the Company was due reimbursement of qualifying claims related to the settlement and associated legal defense costs under the Company's directors and officers liability insurance policies related to the ClassicStar Mare Lease Litigation settled on December 17, 2010 for $21.2 million. The combined coverage limits under the directors and officers liability coverage is $20.0 million. The District Court granted the underwriters' summary judgment request by a ruling dated January 4, 2012. The Company appealed the District Court ruling and on July 15, 2013, the Fourteenth Court of Appeals of Texas reversed the summary judgment ruling granted against the Company on the basis of the policies' prior-and-pending litigation endorsement and remanded the case for further proceedings in the District Court. The District Court proceedings will include, but not be limited to, a determination of whether the Company's claims are securities claims covered by the insuring agreements. The insurers have filed a motion for reconsideration in the Court of Appeals. The insurers may seek discretionary review from the Texas Supreme Court if they do not succeed with their motion for rehearing.

The Company has been expensing legal 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

Table of Contents

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:



	For the Nine Months Ended September 30,
	2013			2012
	(in thousands)
Cash paid for interest	$	1,920		$	1,280
Non-cash transactions:
Capital expenditures excluded from accounts payable and accrued drilling costs	(8,335		)	724
Capital expenditures excluded from prepaid expenses	—			99
Asset retirement obligation included in natural gas and oil properties	1,795			229
Asset retirement obligation assigned to operator	(362		)	(2,099		)
Application of advances to operators	14,443			5,848
Other	61			—

Table of Contents

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 WEHLU Acquisition from the Lime Rock Parties and integrate the acquired assets with ours and realize the anticipated benefits from the transaction;


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


•	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;


•	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;

Table of Contents


•	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 the primarily oil-bearing reservoirs of the Hunton Limestone horizontal oil play in Oklahoma. We also hold prospective Marcellus Shale acreage in Pennsylvania. We sold substantially all of our East Texas assets on October 2, 2013.

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.” On August 2, 2013, Parent obtained a Final Order from the Court of Queen's Bench of Alberta, as amended on September 17, 2013 and October 28, 2013, approving a plan of arrangement pursuant to which Parent shall continue (reincorporate) in Delaware as a Delaware corporation upon properly filing the articles of arrangement. 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 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.”

Table of Contents

Our current operational activities are conducted primarily in the U.S. As of September 30, 2013, our major assets consist of approximately 86,800 gross (65,200 net) acres in the Marcellus Shale in West Virginia and southwestern Pennsylvania, approximately 181,700 gross (99,500 net) acres in Oklahoma and approximately 32,400 gross (16,600 net) acres in the Bossier play in the Hilltop area of East Texas. On June 7, 2013, we acquired approximately 232,500 gross (157,000 net) acres in the Hunton Limestone play in Oklahoma, and effective July 1, 2013, our working interest partner in the original AMI in Oklahoma exercised its rights to acquire approximately 12,800 net acres and certain proved properties associated with this acquisition. In addition, on August 6, 2013, we sold approximately 76,000 net acres in Kingfisher and Canadian Counties, Oklahoma to Newfield Exploration Mid-Continent Inc. (“Newfield”) and acquired from them approximately 2,260 net acres of Oklahoma oil and gas leasehold interests, resulting in net proceeds to us of approximately $54.0 million. On October 2, 2013, we completed the sale of substantially all of the approximately 32,400 gross (16,600 net) acres in the Bossier play in the Hilltop area of East Texas to Cubic Energy for total cash consideration of approximately $43.9 million.

The following discussion addresses material changes in our results of operations for the three and nine months ended September 30, 2013 compared to the three and nine months ended September 30, 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 Part II, 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 September 30, 2013, our acreage position in the play was approximately 86,800 gross (65,200 net) acres. We refer to the approximately 31,800 gross (13,700 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 55,000 gross (51,500 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. We continue to opportunistically swap acreage with adjacent operators in order to optimize our acreage and maximize horizontal lateral lengths.

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 (27.0 net) wells by December 31, 2013. As of September 30, 2013, we had drilled and completed 57 gross (27.0 net) operated wells. All of our 2012 Marcellus Shale well operations were, and all of our 2013 Marcellus Shale well operations have been and will continue to be, under the Atinum Joint Venture.

Table of Contents

As of September 30, 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	3.2	45.0%	37.7%	4,900	November 2012
Lily	4.0	2.0	50.0%	40.6%	5,300	December 2012
Shields	10.0	5.0	50.0%	41.5%	3,400	February and May 2013
Addison	5.0	2.5	50.0%	41.7%	5,000	March 2013
Goudy	4.0	2.0	50.0%	40.5%	6,100	August 2013
	57.0	27.0

_________________________________


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

As of September 30, 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

Goudy⁽²⁾	3.0	1.5	50.0%	40.5%	6,100	Waiting on completion	Second Quarter 2014
Armstrong	9.0	4.5	50.0%	40.5%	5,000	Topholes in progress	Third Quarter 2014
	12.0	6.0

_________________________________


(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 - four of which were placed on production in August 2013 and the remaining of which are scheduled to be on production in the second quarter of 2014.

For the three and nine months ended September 30, 2013, net production from the Marcellus Shale averaged approximately 43.0 MMcfe/d and 38.6 MMcfe/d, respectively, compared to 23.3 MMcfe/d and 19.4 MMcfe/d, respectively, for the three and nine months ended September 30, 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 attempt 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 additional dehydration capacity, bringing total dehydration capacity for our natural gas production to approximately 140 MMcf/d. In mid-April 2013, compression was added at the Burch Ridge CRP to reduce line pressures to approximately 550 psi. We estimate that third-party gathering system downtime and high line pressure during the third quarter of 2013 resulted in reduced production of

Table of Contents

approximately 2.8 MMcfe/d, or 5% of total production, compared to 7.6 MMcfe/d, or 13%, of total second quarter 2013 production and 16.4 MMcfe/d, or 40%, of total first quarter 2013 production. For the quarter ended September 30, 2012, we estimate that gathering system downtime and high line pressure negatively impacted production by approximately 6.0 MMcfe/d, or 16% of total production. We estimate that gathering system downtime for the nine months ended September 30, 2013 resulted in reduced production of approximately 9.0 MMcfe/d, or 17% of total production for the nine months ended September 30, 2013 compared to reduced production of approximately 4.9 MMcfe/d, or 14% of total production for the nine months ended September 30, 2012. We are continuing to work with the third-party gathering system operator to resolve mid-stream downtime issues on our operated Marcellus Shale wells. Currently, we are experiencing no significant curtailment or high line pressure issues on our Marcellus West production on the third-party gathering system. On July 16, 2013, we initiated an arbitration proceeding requesting damages against the gathering system operator for, among other claims, failure to timely construct certain gathering and processing facilities, maximize the net value of produced condensation, and fractionate and purchase NGLs as provided in the agreements, see Part I, Item 1. “Financial Statements, Note 13, “Commitments and Contingencies” of this report. In the event that the third-party gathering system operator is unable to resolve these issues, we have developed a plan that we believe could be implemented in approximately four to six months whereby a new third party would handle all of our condensate production. During October 2013, our Marcellus Shale production was negatively impacted by a leak in the third-party operated pipeline. The leak has been repaired, however, we estimate that the downtime will result in an estimated loss of approximately 1.3 MMcfe/d of fourth quarter 2013 total production.

Mid-Continent Horizontal Oil Play. At September 30, 2013, we held leases covering approximately 181,700 gross (99,500 net) acres in Major, Garfield, Canadian and Kingfisher Counties, Oklahoma in the Hunton Limestone horizontal oil play.

On June 7, 2013, Gastar USA acquired approximately 157,000 net acres of Oklahoma oil and gas leasehold interests in Canadian and Kingfisher Counties, Oklahoma from the Chesapeake Parties, including production from interests in 206 producing wells located in Oklahoma, for an adjusted cash purchase price of approximately $69.4 million (reflecting adjustment for an acquisition effective date of October 1, 2012). The Chesapeake Purchase Agreement contains customary representations, warranties and covenants, including provisions for indemnification, subject to the limitations described in the Chesapeake Purchase Agreement. Effective July 1, 2013, Gastar USA's working interest partner in its original AMI in Oklahoma exercised its rights to acquire approximately 12,800 net acres and certain proved properties that Gastar USA acquired pursuant to the Chesapeake Purchase Agreement for a total payment of $12.1 million. In addition, on August 6, 2013, we sold approximately 76,000 net acres in Kingfisher and Canadian Counties, Oklahoma to Newfield for an adjusted purchase price of approximately $54.0 million cash and approximately 2,260 net acres of Oklahoma oil and gas leasehold interests.

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 September 30, 2013 and currently as of the date of this report, we had production and drilling operations at various stages on the following wells in our original AMI in the Hunton Limestone formation:

Table of Contents



				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 Gross Costs to Drill & Complete ($ millions)

Mid-Con 1H	50.0%	39.0%	4,200	18	63	29	Producing - October 5, 2012	$5.0
Mid-Con 2H	50.0%	39.0%	4,100	291	1,432	529	Producing - February 15, 2013⁽²⁾	$5.3
Mid-Con 3H⁽³⁾	70.9%	55.3%	4,300	54	20	58	Producing - April 4, 2013⁽⁴⁾	$5.1
Mid-Con 4H	50.0%	39.0%	4,200	57	217	94	Producing - April 24, 2013⁽⁵⁾	$4.8
Mid-Con 5H	50.0%	39.0%	4,600	248	478	327	Producing - August 23, 2013⁽⁶⁾	$6.1
Mid-Con 6H	50.0%	39.0%	4,100	N/A	N/A	N/A	Initial flowback - October 6, 2013⁽⁷⁾	$4.7
Mid-Con 7H	50.0%	39.0%	4,100	N/A	N/A	N/A	Completion operations in progress	$5.2

_________________________________


(1)	Current production rates are based on the 30 days ended October 23, 2013.


(2)	Well has recovered approximately 25% of completion fluids as of October 23, 2013.


(3)	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%.


(4)	Well has recovered approximately 49% of completion fluids as of October 23, 2013.


(5)	Well has recovered approximately 42% of completion fluids as of October 23, 2013.


(6)	Well has recovered approximately 21% of completion fluids as of October 23, 2013. Due to mechanical issues, the well is estimated to be producing from only 8 of 20 frac stages at this time. Increase in well costs is due to the cost of side-tracking the well during the initial drilling operations.


(7)	Well has recovered approximately 14% of completion fluids as of November 4, 2013 and is currently producing 667 barrels of oil and 641 Mcf of natural gas per day.

We continue to target the horizontal laterals in the lower Hunton Limestone formation and increase the number of fracs in the horizontal lateral as warranted by log analysis. We are continuing to monitor well flow back results and remain encouraged by the high volumes of completion fluids being flowed back on recently completed wells and early oil cuts.

We spudded our first operated Hunton well, the Burton 16-1H (79% working interest and approximate 81% net revenue interest), on our existing Mid-Continent acreage at the beginning of October 2013. The well reached total depth in 26 days and completion operations will commence in early November 2013. We are planning to commence drilling operations on our second operated Hunton well, the Townsend 6-1H (100% working interest and approximate 80% net revenue interest), in early November 2013. Production operations on the Burton 16-1H and the Townsend 6-1H are expected to begin by late November 2013 and late December 2013, respectively.

Table of Contents

We have also participated in 3.0 gross (0.9 net) wells outside of our AMI acreage targeting the Hunton Limestone formation, the Woodford Shale and the Mississippi Lime.

On September 4, 2013, we entered into the WEHLU Purchase Agreement to acquire a 98.3% working interest (80.5% net revenue interest) in 24,000 net acres of the WEHLU located in Kingfisher, Logan and Oklahoma Counties, Oklahoma, for a cash purchase price of $187.5 million, subject to, among other customary adjustments, adjustment for an acquisition effective date of August 1, 2013. We paid a deposit of $9.4 million, which will be applied to the purchase price at closing which is scheduled to occur in late November 2013.

For the three and nine months ended September 30, 2013, net production from the Mid-Continent averaged approximately 7.0 MMcfe/d and 3.9 MMcfe/d, respectively, of which 34% and 46%, respectively, was oil.

Hilltop Area, East Texas. At September 30, 2013, we held leases covering approximately 32,400 gross (16,600 net) acres in the Bossier play in the Hilltop area of East Texas in Leon and Robertson Counties. On October 2, 2013, we sold substantially all of our leasehold interests consisting of 31,800 gross (16,300 net) acres and producing wells in the Hilltop area of East Texas to Cubic Energy for net proceeds of approximately $43.9 million, reflecting adjustment for accounting effective date of January 1, 2013 and other customary adjustments and $4.7 million that was previously received as a deposit and accounted for in other liabilities at September 30, 2013.

For the three and nine months ended September 30, 2013, net production from the Hilltop area averaged approximately 9.3 MMcfe/d and 9.9 MMcfe/d, respectively, compared to 14.6 MMcfe/d and 14.1 MMcfe/d for the three and nine months ended September 30, 2012, respectively. 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.

Table of Contents

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



	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2013		2012		2013		2012
Production:
Natural gas (MMcf)	3,866		2,783		10,257		7,584
Condensate and oil (MBbl)	128		42		333		106
NGLs (MBbl)	137		77		347		186
Total production (MMcfe)	5,454		3,493		14,338		9,339
Daily Production:
Natural gas (MMcf/d)	42.0		30.2		37.6		27.7
Condensate and oil (MBbl/d)	1.4		0.5		1.2		0.4
NGLs (MBbl/d)	1.5		0.8		1.3		0.7
Total daily production (MMcfe/d)	59.3		38.0		52.5		34.1
Average sales price per unit:
Natural gas per Mcf, excluding impact of realized hedging activities	$	2.61	$	2.27	$	2.94	$	1.99
Natural gas per Mcf, including impact of realized hedging activities	2.95		3.20		3.38		2.97
Condensate and oil per Bbl, excluding impact of realized hedging activities	73.40		76.54		68.26		68.93
Condensate and oil per Bbl, including impact of realized hedging activities	67.92		83.05		68.54		72.93
NGLs per Bbl, excluding impact of realized hedging activities	33.79		25.26		30.01		29.02
NGLs per Bbl, including impact of realized hedging activities	27.54		32.40		30.80		34.31
Average sales price per Mcfe, excluding impact of realized hedging activities	$	4.42	$	3.28	$	4.41	$	2.98
Average sales price per Mcfe, including impact of realized hedging activities	4.37		4.25		4.76		3.92
Selected operating expenses (in thousands):
Production taxes	$	1,319	$	560	$	3,112	$	1,494
Lease operating expenses	2,190		780		6,196		4,754
Transportation, treating and gathering	1,098		1,305		3,386		3,715
Depreciation, depletion and amortization	8,467		7,135		21,428		19,744
Impairment of natural gas and oil properties	—		78,054		—		150,787
General and administrative expense ⁽¹⁾	3,998		2,951		11,964		9,263
Selected operating expenses per Mcfe:
Production taxes	$	0.24	$	0.16	$	0.22	$	0.16
Lease operating expenses	0.40		0.22		0.43		0.51
Transportation, treating and gathering	0.20		0.37		0.24		0.40
Depreciation, depletion and amortization	1.55		2.04		1.49		2.11
General and administrative expense	0.73		0.84		0.83		0.99
Production costs ⁽²⁾	0.61		0.60		0.64		0.86

_________________________________


(1)	The three and nine months ended September 30, 2013 include non-recurring acquisition expenses related to the acquisition of the Chesapeake Assets and employee severance costs related to the East Texas divestiture of $529,000 and $1.9 million, respectively.


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

Table of Contents

Three Months Ended September 30, 2013 compared to the Three Months Ended September 30, 2012

Revenues. Total natural gas, condensate, oil and NGLs revenues were $23.8 million for the three months ended September 30, 2013, up 61% from $14.8 million for the three months ended September 30, 2012. The increase in revenues was the result of a 56% increase in production and a 3% increase in weighted average realized prices. Average daily production on an equivalent basis was 59.3 MMcfe/d for the three months ended September 30, 2013 compared to 38.0 MMcfe/d for the same period in 2012. Condensate, oil and NGLs production represented approximately 29% of total production for the three months ended September 30, 2013 compared to 20% of total production for the three months ended September 30, 2012, and 29% of total production for the three months ended June 30, 2013. Production for the quarter ended September 30, 2013 increased 4% from the production for the quarter ended June 30, 2013 due to four gross (2.0 net) new Marcellus Shale horizontal wells and one gross (0.5 net) Hunton well were brought on production at approximately mid-way through the third quarter of 2013, as well as having a full quarter of production from the assets acquired from Chesapeake net of assets sold in the AMI Election disposition on July 1, 2013 and the Hunton Disposition on August 6, 2013.

Liquids revenues (condensate, oil and NGLs) represented approximately 52% of our total natural gas, condensate and oil and NGLs revenues for the three month period ended September 30, 2013 compared to 40% for the three month period ended September 30, 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.

During the three months ended September 30, 2013, we had commodity derivative contracts covering approximately 63% of our natural gas production, which resulted in realized gains of $1.3 million, comprised of $1.3 million in NYMEX hedge gains offset by $28,000 of regional basis losses and non-cash premium amortization of $10,000, and resulted in an increase in total price realized from $2.61 per Mcf to $2.95 per Mcf. For additional information regarding our natural gas hedging positions as of September 30, 2013, see Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report. During the three months ended September 30, 2012, the realized effect of hedging on natural gas sales was an increase of $2.6 million in natural gas revenues resulting in an increase in total price realized from $2.27 per Mcf to $3.20 per Mcf. The 2012 realized hedge impact included a benefit of $222,000 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 September 30, 2013, we had commodity derivative contracts covering approximately 66% of our condensate and oil production. The realized effect of hedging on condensate and oil sales during the three months ended September 30, 2013 was a decrease of $701,000 in condensate and oil revenues resulting in a decrease in total price realized from $73.40 per Bbl to $67.92 per Bbl. For additional information regarding our oil hedging positions as of September 30, 2013, see Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report. During the three months ended September 30, 2012, the realized effect of hedging on condensate and oil sales was an increase of $271,000 in condensate and oil revenues which resulted in an increase in total price realized from $76.54 per Bbl to $83.05 per Bbl. For both periods, we designated 50% of our current crude hedges as price protection for our NGLs production. On a combined liquids basis (condensate, oil and NGLs), approximately 81% of our liquids production volumes were hedged during the quarter ended September 30, 2013.

During the three months ended September 30, 2013, we had commodity derivative contracts covering approximately 95% of our NGLs production. The realized effect of hedging on NGLs sales during the three months ended September 30, 2013 was a decrease of $855,000 in NGLs revenues resulting in a decrease in total price realized from $33.79 per Bbl to $27.54 per Bbl. For additional information regarding our NGLs hedging positions as of September 30, 2013, see Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report. During the three months ended September 30, 2012, the realized effect of hedging on NGLs sales was an increase of $547,000 in NGLs revenues which resulted in an increase in total price realized from $25.26 per Bbl to $32.40 per Bbl.

Unrealized hedge loss was $5.0 million for the three months ended September 30, 2013 compared to $5.4 million for the three months ended September 30, 2012. The decrease in unrealized hedge loss is the result of lower 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 $1.3 million for the three months ended September 30, 2013 compared to $560,000 for the three months ended September 30, 2012. The increase in production taxes primarily resulted from higher revenues in West Virginia and Oklahoma due to increased natural gas, condensate, oil and NGLs production resulting from new wells on production and wells acquired. Production taxes for the three months ended September 30, 2013 were approximately 6% of condensate, oil and NGLs revenues compared to 4% for the three months ended September 30, 2012.

Lease operating expenses. We reported lease operating expenses (“LOE”) of $2.2 million for the three months ended September 30, 2013 compared to $780,000 for the three months ended September 30, 2012. Our total LOE was $0.40 per Mcfe for the three months ended September 30, 2013 compared to $0.22 per Mcfe for the same period in 2012. The increase in our LOE was primarily due to a $1.4 million increase in controllable LOE. This increase is primarily due to bringing new wells

Table of Contents

on production in West Virginia and Oklahoma and a reduction of $394,000 for the three months ended September 30, 2012 related to property assignments in East Texas.

Transportation, treating and gathering. We reported transportation expenses of $1.1 million for the three months ended September 30, 2013 compared to $1.3 million for the three months ended September 30, 2012, of which $951,000 and $944,000, respectively, related to our Hilltop operations in East Texas. The current quarter includes $644,000 of minimum volume requirement charges under our Hilltop gas gathering agreement compared to $509,000 of such charges in the same quarter of 2012. Such charges resulted from actual production volumes being less than minimum contractual volume requirements. Cubic Energy has assumed any future minimum volume requirement obligations.

Depreciation, depletion and amortization. We reported depreciation, depletion and amortization (“DD&A”) expense of $8.5 million for the three months ended September 30, 2013 up from $7.1 million for the three months ended September 30, 2012. The increase in DD&A expense was the result of a 56% increase in production offset by a 24% decrease in the DD&A rate per Mcfe. The DD&A rate for the three months ended September 30, 2013 was $1.55 per Mcfe compared to $2.04 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 $4.0 million for the three months ended September 30, 2013, up from $3.0 million for the three months ended September 30, 2012. Non-cash stock-based compensation expense, which is included in general and administrative expense, decreased $155,000 to $574,000 for the three months ended September 30, 2013 compared to the three months ended September 30, 2012. The decrease in stock-based compensation expense is due to a $422,000 reduction for forfeitures related to staff reductions as a result of the sale of the East Texas assets partially offset by increased expense for additional share issuances. Excluding stock-based compensation expense, general and administrative expense increased $1.2 million to $3.4 million for the three months ended September 30, 2013 compared to the three months ended September 30, 2012. This increase is primarily due to higher personnel costs, including $659,000 of severance costs resulting from staff reductions in conjunction with the sale of our East Texas assets and $292,000 of non-recurring costs associated with property acquisitions.

Interest expense. We reported interest expense of $3.4 million for the three months ended September 30, 2013 compared to $30,000 for the three months ended September 30, 2012. The increase in interest expense is directly related to the increase in long-term debt from 2012 to 2013 primarily as a result of the issuance of the $200.0 million 8 5/8% Senior Secured Notes in May 2013, a lower capitalized interest percentage resulting from higher debt balances when compared to total interest expense and increased amortization of debt costs.

Dividends on Preferred Stock. We reported dividend expense on our Series A Preferred Stock of $2.1 million for the three months ended September 30, 2013 compared to $2.0 million for the three months ended September 30, 2012. The Series A Preferred Stock had a stated value of approximately $76.8 million and $65.8 million at September 30, 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 3,958,160 shares of Series A Preferred Stock outstanding at September 30, 2013 compared to 3,946,950 shares at September 30, 2012. Based on the number of shares of Series A Preferred Stock outstanding at September 30, 2013, our stated preferred dividend expense is $2.1 million per quarter, which is subject to being declared and paid monthly. Including the shares of Series B Preferred Stock that are expected to be issued on or about November 5, 2013, our stated preferred dividend expense will be $3.5 million per quarter, which is subject to being declared and paid monthly.

Nine Months Ended September 30, 2013 compared to the Nine Months Ended September 30, 2012

Revenues. Total natural gas, condensate, oil and NGLs revenues were $68.2 million for the nine months ended September 30, 2013, up 86% from $36.6 million for the nine months ended September 30, 2012. The increase in revenues was the result of a 54% increase in production and a 21% increase in weighted average realized prices. Average daily production on an equivalent basis was 52.5 MMcfe/d for the nine months ended September 30, 2013 compared to 34.1 MMcfe/d for the same period in 2012. Condensate, oil and NGLs production represented approximately 28% of total production for the nine months ended September 30, 2013 compared to 19% of total production for the nine months ended September 30, 2012 The increase in total liquids (condensate, oil and NGLs) production is primarily the result of our increased focus on drilling liquids-rich acreage in our successful Marcellus Shale area and the Hunton Limestone oil play in Oklahoma.

Liquids revenues represented approximately 49% of our total natural gas, condensate and oil and NGLs revenues for the nine month period ended September 30, 2013 compared to 39% for the nine month period ended September 30, 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.

Table of Contents

During the nine months ended September 30, 2013, we had commodity derivative contracts covering approximately 70% of our natural gas production, which resulted in realized gains of $4.6 million, comprised of $4.7 million in NYMEX hedge gains offset by $101,000 of regional basis losses and non-cash premium amortization of $17,000, and resulted in an increase in total price realized from $2.94 per Mcf to $3.38 per Mcf. For additional information regarding our natural gas hedging positions as of September 30, 2013, see Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report. During the nine months ended September 30, 2012, the realized effect of hedging on natural gas sales was an increase of $7.5 million in natural gas revenues resulting in an increase in total price realized from $1.99 per Mcf to $2.97 per Mcf. The 2012 realized hedge impact included a benefit of $662,000 of non-cash amortization of prepaid call sale and put purchase premiums and payment of deferred put premiums of $3.2 million.

During the nine months ended September 30, 2013, we had commodity derivative contracts covering approximately 45% of our condensate and oil production. The realized effect of hedging on condensate and oil sales during the nine months ended September 30, 2013 was an increase of $92,000 in condensate and oil revenues resulting in an increase in total price realized from $68.26 per Bbl to $68.54 per Bbl. For additional information regarding our oil hedging positions as of September 30, 2013, see Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report. During the nine months ended September 30, 2012, the realized effect of hedging on condensate and oil sales was an increase of $425,000 in condensate and oil revenues which resulted in an increase in total price realized from $68.93 per Bbl to $72.93 per Bbl. For both periods, we designated 50% of our current crude hedges as price protection for our NGLs production. On a combined liquids basis (condensate, oil and NGLs), approximately 59% of our liquids production volumes were hedged during the nine months ended September 30, 2013

During the nine months ended September 30, 2013, we had commodity derivative contracts covering approximately 72% of our NGLs production. The realized effect of hedging on NGLs sales during the nine months ended September 30, 2013 was an increase of $275,000 in NGLs revenues resulting in an increase in total price realized from $30.01 per Bbl to $30.80 per Bbl. For additional information regarding our NGLs hedging positions as of September 30, 2013, see Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report. During the nine months ended September 30, 2012, the realized effect of hedging on NGLs sales was an increase of $987,000 in NGLs revenues which resulted in an increase in total price realized from $29.02 per Bbl to $34.31 per Bbl.

Unrealized hedge loss was $7.2 million for the nine months ended September 30, 2013 compared to an unrealized hedge gain of $4.1 million for the nine months ended September 30, 2012. The increase in unrealized hedge loss is the result of changes in future NYMEX natural gas prices and future oil and NGLs prices coupled with changes in hedged volumes.

Production taxes. We reported production taxes of $3.1 million for the nine months ended September 30, 2013 compared to $1.5 million for the nine months ended September 30, 2012. The increase in production taxes primarily resulted from higher revenues in West Virginia and Oklahoma due to increased natural gas, condensate, oil and NGLs production. Production taxes for the nine months ended September 30, 2013 were approximately 5% of condensate, oil and NGLs revenues compared to 4% for the nine months ended September 30, 2012.

Lease operating expenses. We reported lease operating expenses of $6.2 million for the nine months ended September 30, 2013 compared to $4.8 million for the nine months ended September 30, 2012. Our total LOE was $0.43 per Mcfe for the nine months ended September 30, 2013 compared to $0.51 per Mcfe for the same period in 2012. The decrease in our LOE per Mcfe was primarily due to higher production volumes. Current period total LOE expense benefited by $441,000 due to the assignment of our Powder River Basin properties to the operator on May 3, 2012 and $482,000 due to reduced activity in East Texas for the nine months ended September 30, 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 and total producing wells.

Transportation, treating and gathering. We reported transportation expenses of $3.4 million for the nine months ended September 30, 2013 compared to $3.7 million for the nine months ended September 30, 2012, of which $2.8 million for the nine months ended September 30, 2013 and 2012, respectively, related to our Hilltop operations in East Texas. The current year to date period includes $1.8 million of minimum volume requirement charges under our Hilltop gas gathering agreement compared to $1.5 million of such charges in the same period of 2012. Such charges resulted from actual production volumes being less than minimum contractual volume requirements. Cubic Energy has assumed any future minimum volume requirement obligations.

Depreciation, depletion and amortization. We reported DD&A expense of $21.4 million for the nine months ended September 30, 2013 up from $19.7 million for the nine months ended September 30, 2012. The increase in DD&A expense was the result of a 54% increase in production offset by a 29% decrease in the DD&A rate per Mcfe. The DD&A rate for the nine months ended September 30, 2013 was $1.49 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.

Table of Contents

General and administrative expense. We reported general and administrative expenses of $12.0 million for the nine months ended September 30, 2013, up from $9.3 million for the nine months ended September 30, 2012. Non-cash stock-based compensation expense, which is included in general and administrative expense, increased $35,000 to $2.5 million for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012. The decrease in stock-based compensation expense is due to a $422,000 reduction for forfeitures related to staff reductions as a result of the sale of the East Texas assets partially offset by increased expense for additional share issuances. Excluding stock-based compensation expense, general and administrative expense increased $2.7 million to $9.4 million for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012. This increase is primarily due to $1.7 million of non-recurring costs associated with property acquisitions and higher personnel costs primarily related to $659,000 of severance costs resulting from staff reductions in conjunction with the sale of our East Texas assets.

Litigation settlement expense. We reported litigation settlement expense of $1.0 million for the nine months ended September 30, 2013, resulting from our settlement with Chesapeake on March 28, 2013, compared to $1.3 million for the nine months ended September 30, 2012 resulting from our settlement with Navasota Resources L.P. For additional information regarding the settlement of the Chesapeake matter, see Part I, Item 1. “Financial Statements, Note 13, “Commitments and Contingencies” of this report.

Gain on acquisition of assets at fair value. We reported a bargain purchase gain of $43.7 million for the nine months ended September 30, 2013 for the acquisition of the Chesapeake Assets. Our preliminary assessment of the fair value of the Chesapeake Assets resulted in a fair market valuation of $113.5 million. As a result of incorporating the valuation information into the purchase price allocation, a bargain purchase gain of $43.7 million was recognized. The bargain purchase gain was primarily attributable to the non-strategic nature of the divestiture to the seller, coupled with favorable economic trends in the industry and the geographic region in which the Chesapeake Assets are located.

Interest expense. We reported interest expense of $7.6 million for the nine months ended September 30, 2013 compared to $86,000 for the nine months ended September 30, 2012. The increase in interest expense is directly related to the increase in long-term debt from 2012 to 2013 primarily as a result of the issuance of the $200.0 million 8 5/8% Senior Secured Notes in May 2013, a lower capitalized interest percentage when compared to total interest expense and increased amortization of debt costs including a non-recurring cost of $1.2 million related to the termination of the Old Amended Revolving Credit Facility.

Dividends on Preferred Stock. We reported dividend expense on our Series A Preferred Stock of $6.4 million for the nine months ended September 30, 2013 compared to $4.9 million for the nine months ended September 30, 2012. The Series A Preferred Stock had a stated value of approximately $76.8 million and $65.8 million at September 30, 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 3,958,160 shares of Series A Preferred Stock outstanding at September 30, 2013 compared to 3,946,950 shares at September 30, 2012. Based on the number of shares of Series A Preferred Stock outstanding at September 30, 2013, our stated preferred dividend expense is $2.1 million per quarter, which is subject to being declared and paid monthly. Including the shares of Series B Preferred Stock that are expected to be issued on or about November 5, 2013, our stated preferred dividend expense will be $3.5 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, to the extent available, access to capital markets. 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 nine months ended September 30, 2013, we reported cash flows provided by operating activities of $39.2 million. For the nine months ended September 30, 2013, we reported net cash used in investing activities of $104.1 million primarily for the acquisition, development and purchase of natural gas and oil properties, including $78.8 million for the purchase of the Chesapeake Assets and net proceeds of $70.7 million from the AMI election and the sale of acreage to Newfield. For the nine months ended September 30, 2013, we reported net cash provided by financing activities of $77.3 million, consisting of net proceeds from the issuance of Notes of $194.5 million less $98.0 million of net repayments under our Amended and Restated Revolving Credit Facility, $9.8 million for the repurchase of our common shares, $6.4 million of dividends paid on the preferred stock and $2.8 million of deferred finance charges. As a result of these activities, our cash and cash equivalents balance increased by $12.5 million, resulting in a cash and cash equivalents balance of $21.4 million at September 30, 2013.

At September 30, 2013, we had a net working capital deficit of approximately $16.6 million, including $13.0 million of advances from non-operators. On October 2, 2013, we sold substantially all of our leasehold interests and producing wells in the Hilltop area of East Texas for an adjusted cash purchase price of approximately $43.9 million reflecting adjustment for

Table of Contents

accounting effective date of January 1, 2013 and other customary adjustments and the $4.7 million that was previously received as a cash deposit. At September 30, 2013, availability under our Revolving Credit Facility was $50.0 million.

On October 29, 2013, Gastar USA announced the pricing of an underwritten public offering of 2,000,000 shares of its 10.75% Series B Cumulative Preferred Stock, par value $0.01 per share and liquidation preference $25.00 per share (the “Series B Preferred Stock”). On November 1, 2013, the underwriters partially exercised their option to purchase additional shares of Series B Preferred Stock and will purchase an additional 140,000 shares of Series B Preferred Stock. The issuance of the 2,140,000 shares of Series B Preferred Stock is expected to close on or about November 5, 2013 with total net proceeds to us from the offering expected to be approximately $50.1 million after deducting underwriting commissions and estimated offering expenses.

Future capital and other expenditure requirements. Capital expenditures for the remainder of 2013, excluding acquisitions, are projected to be approximately $34.5 million. In the Marcellus Shale and Mid-Continent, we expect to spend $5.9 million and $26.1 million, respectively, for drilling, completion, infrastructure, lease acquisition and seismic costs and $2.5 million for capitalized interest and other costs. The 2013 remaining net capital expenditures in the Mid-Continent includes $19.1 million related to planned activities on the Chesapeake Assets acquired. We plan to fund our remaining 2013 capital budget and the additional drilling related to the Chesapeake Assets acquired through existing cash balances, internally generated cash flow from operating activities, borrowings under the Revolving Credit Facility and proceeds from the divestiture of our East Texas assets and certain non-strategic acreage acquired from Chesapeake, each as previously announced. In addition, we anticipate closing the $187.5 million WEHLU Acquisition (approximately $169.1 million net after closing adjustments and the application of the $9.4 million deposit previously paid) in November 2013 and anticipate financing the acquisition with some combination of cash on hand, including net proceeds from the issuance of Series B Preferred Stock, and the possible future issuance of additional senior secured notes. Our future 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 or changes in the borrowing base under the New Revolving Credit Facility and access to the capital markets. We operate approximately 78% of our remaining budgeted 2013 drilling and land capital expenditures, 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 September 30, 2013, the estimated fair value of all of our commodity derivative instruments was a net asset of $8.9 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. In conjunction with certain commodity derivative hedging activity, we deferred the payment of certain put premiums for the production month December 2013 through August 2018. At September 30, 2013, we had a current commodity premium payable of $1.8 million and a long-term commodity premium payable of $7.7 million. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month beginning in December 2013.

As of September 30, 2013, all of our commodity derivative hedge positions were with a multinational energy company or large financial institution, each of which is not known to us to be in default on their derivative positions. 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 June 7, 2013, our Old Revolving Credit Facility was replaced with our New Revolving Credit Facility which provides an initial borrowing base of $50.0 million. At September 30, 2013, we did not have any balance outstanding under our New Revolving Credit Facility, compared to our December 31, 2012 outstanding balance of $98.0 million under our Old Amended Revolving Credit Facility. Borrowing base redeterminations are scheduled semi-annually with

Table of Contents

the next redetermination scheduled for November 2013. However, we and the lenders may each request one additional unscheduled redetermination during any six-month period between scheduled redeterminations. Future increases in the borrowing base in excess of the $50.0 million are limited to 17.5% of the increase in adjusted consolidated net tangible assets (“ACNTA”) as defined in the Notes agreement. We estimate that the borrowing base will increase in November 2013 from $50.0 million to between $90.0 and $110.0 million based on the ACNTA definition.

Borrowings under the New Revolving Credit Facility bear interest, at our election, at the reference rate or the Eurodollar rate plus an applicable margin. Pursuant to the New Revolving Credit Facility, the reference rate is the greater of (i) the rate of interest publicly announced by the administrative agent, (ii) the federal funds rate plus 50 basis points, or (iii) a LIBOR rate. The applicable interest rate margin varies from 1.0% to 2.0% in the case of borrowings based on the reference rate and from 2.0% to 3.0% in the case of borrowings based on the Eurodollar rate, depending on the utilization percentage in relation to the borrowing base. Under the New Revolving Credit Facility, we are subject to certain financial covenants, including interest coverage ratio, a total net indebtedness to EBITDA ratio and current ratio requirement. At November 4, 2013, our availability under our New Revolving Credit Facility was $50.0 million. If the WEHLU Acquisition is completed, we anticipate that our borrowing base will increase to between $90.0 and $110.0 million.

At September 30, 2013, we were in compliance with all financial covenants under the New Revolving Credit Facility. For a more detailed description of the terms of our New Revolving Credit Facility, see Part I, Item 1. “Financial Statements, Note 4 – Long-Term Debt” of this report.

Senior Secured Notes. On May 15, 2013, we issued $200.0 million aggregate principal amount of 8 5/8% Senior Secured Notes due 2018 in a private placement offering under an indenture. The Notes bear interest at a rate of 8.625% per year, payable semiannually in arrears on May 15 and November 15 of each year, beginning on November 15, 2013. The Notes will mature on May 15, 2018. For a more detailed description of the terms of our Notes, see Part I, Item 1. “Financial Statements, Note 4 – Long-Term Debt” of this report. At September 30, 2013, we were in compliance with all covenants under the indenture governing the Notes. We anticipate issuing additional senior secured notes to fund a portion of the WEHLU Acquisition.

Series B Preferred Stock. On or about November 5, 2013, we expect to issue 2,140,000 shares of 10.75% Series B Preferred Stock at the stated par value of $25.00 per share for net proceeds of $50.1 million. The net proceeds from the issuance of the Series B Preferred Stock will be used to partially fund the pending WEHLU Acquisition anticipated to close in November 2013, if such acquisition is completed. We intend to finance the remainder of the purchase price with cash on hand or from a possible issuance of Notes. Should the WEHLU Acquisition not close, we intend to use the proceeds to accelerate our drilling program, primarily in the Hunton Limestone area. Based on the number of shares of Series A Preferred Stock outstanding at September 30, 2013 and the Series B Preferred Stock to be issued on or about November 5, 2013, our stated preferred dividend expense for the fourth quarter of 2013 is estimated to be $3.1 million and $3.5 million per quarter thereafter, subject to being declared and paid monthly.

Off-Balance Sheet Arrangements

As of September 30, 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.

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:

Table of Contents


•	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 and nine months ended September 30, 2013, a 10% change in the prices received for natural gas, condensate, oil and NGLs production would have had an approximate $2.4 million and $6.3 million impact, respectively, on our revenues prior to hedge transactions to mitigate our commodity pricing risk. See Part I, Item 1. “Financial Statements, Note 6 – Derivative Instruments and Hedging Activity” of this report for additional information regarding our hedging activities.

Interest Rate Risk

At September 30, 2013, we had did not have any debt outstanding under the Revolving Credit Facility. The amount outstanding under the Notes is at fixed interest of 8.625% per annum. 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

Gastar Exploration Ltd.

Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of Parent, Parent conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (“Exchange Act”), as of September 30, 2013. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of Parent concluded that, as of September 30, 2013, the Parent's disclosure controls and procedures were effective in providing reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer of Parent, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in Parent's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended September 30, 2013 that has materially affected, or is reasonably likely to materially affect, Parent's internal control over financial reporting.

Gastar Exploration USA, Inc.

Under the supervision and with the participation of our management, including the President and Treasurer of Gastar USA, Gastar USA conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (“Exchange Act”), as of September 30, 2013. Based on that evaluation, the President and Treasurer of Gastar USA concluded that, as of September 30, 2013, Gastar USA's disclosure controls and procedures were effective in providing reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is

Table of Contents

accumulated and communicated to our management, including the President and Treasurer of Gastar USA, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in Gastar USA's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended September 30, 2013 that has materially affected, or is reasonably likely to materially affect, Gastar USA's internal control over financial reporting.

Table of Contents

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 and nine months ended September 30, 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 representations, 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.

We may not complete the pending WEHLU Acquisition.

The closing of this offering is not subject to a condition that we successfully complete the pending WEHLU Acquisition. There can be no assurance that the pending WEHLU Acquisition will be completed or, if completed, that it will be completed on the terms described in this prospectus supplement.

The representation, warranties and indemnifications of Lime Rock contained in the purchase and sale agreement are limited; as a result, the assumptions on which our estimates of future results of the WEHLU 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 pending WEHLU Acquisition. The pending WEHLU Acquisition could also expose us to additional unknown and contingent liabilities.

The representations and warranties of Lime Rock contained in the purchase and sale agreement are limited. In addition, the purchase and sale agreement provides limited indemnities. As a result, the assumptions on which our estimates of future results of the WEHLU 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 pending WEHLU Acquisition, including anticipated increased cash flow.

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

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

Table of Contents

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosure

Not applicable.

Item 5. Other Information

The unaudited pro forma combined financial statements of Gastar Exploration Ltd. and Gastar Exploration USA, Inc. as of and for the nine months ended September 30, 2013 and for the year ended December 31, 2012 are included as Exhibit 99.1 to this Quarterly Report on Form 10-Q and are incorporated herein by reference. The unaudited pro forma financial information contained in Exhibit 99.1 is derived from the historical financial statements of Gastar Exploration Ltd. and Gastar Exploration USA, Inc. and the audited and unaudited statements of revenues and direct operating expenses of the assets acquired in the Chesapeake Acquisition and the assets proposed to be acquired in the WEHLU Acquisition, and reflect the impact of the WEHLU Acquisition, East Texas Divestiture, the Hunton Transactions, the Newfield Divestiture and the Preferred Stock Sale, as each of such capitalized terms are defined in Exhibit 99.1, and a proposed issuance of additional senior secured notes as described therein.

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		Second Amendment of Purchase and Sale Agreement, dated as of June 27, 2013, but effective as June 5, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated herein by reference to Exhibit 2.1 of the Company's Current Report on Form 8-K dated July 3, 2013. File No. 001-32714).

2.2		Third Amendment of Purchase and Sale Agreement, dated as of July 11, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated herein by reference to Exhibit 2.1 of the Company's Current Report on Form 8-K dated July 17, 2013. File No. 001-32714).

2.3		Purchase and Sale Agreement, dated as of July 2, 2013, by and among Newfield Exploration Mid-Continent Inc. and Gastar Exploration USA, Inc. (incorporated herein by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K dated August 12, 2013. File. No. 001-32714).

2.4		Fourth Amendment of Purchase and Sale Agreement, dated July 31, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated herein by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K dated August 5, 2013. File. No. 001-32714).

2.5		Fifth Amendment of Purchase and Sale Agreement, dated August 29, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated herein by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K dated September 3, 2013. File. No. 001-32714).

2.6*		Purchase and Sale Agreement, dated September 4, 2013, by and among Gastar Exploration USA, Inc., Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P. (incorporated herein by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K dated October 28, 2013. File. No. 001-32714).

2.7		Sixth Amendment of Purchase and Sale Agreement, dated September 20, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated herein by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K dated September 23, 2013. File. No. 001-32714).

2.8		Letter Agreement to Purchase and Sale Agreement, dated September 30, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated herein by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K dated October 4, 2013. File. No. 001-32714).

Table of Contents



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

3.2		Amended Bylaws of Gastar Exploration Ltd. dated as of June 3, 2010 (incorporated herein by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated June 4, 2010. File No. 001-32714).

3.3		Articles of Amendment and Share Structure attached to and forming part of the Amended and Restated Articles of Incorporation of Gastar Exploration Ltd, dated as of June 30, 2009. (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated July 1, 2009. File No. 001-32714).

3.4		Articles of Amendment attached to and forming part of the Amended and Restated Articles of Incorporation of Gastar Exploration Ltd, dated as of July 23, 2009 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated July 24, 2009. File No. 001-32714).

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

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

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

3.8		Certificate of Designation of Rights and Preferences of 10.75% Series B Cumulative Preferred Stock (incorporated by reference to Exhibit 4.3 of Gastar Exploration USA, Inc.’s Form 8A filed on October 31, 2013).

10.1		Waiver, Agreement and Amendment No. 1 to Second Amended and Restated Credit Agreement, dated as of July 31, 2013, among Gastar Exploration USA, Inc., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and Issuing Lender, and the Lenders named therein (incorporated herein by reference to Exhibit 10.3 of the Company's Quarterly Report on Form 10-Q dated August 5, 2013. File No. 001-32714).

10.2		Agreement and Amendment No. 2 to Second Amended and Restated Credit Agreement, dated as of October 18, 2013, among Gastar Exploration USA, Inc., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and Issuing Lender, and the Lenders named therein (incorporated herein by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K dated October 22, 2013. File No. 001-32714).

31.1†		Certification of Principal Executive Officer of Gastar Exploration Ltd. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2†		Certification of Principal Financial Officer of Gastar Exploration Ltd. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.3†		Certification of Principal Executive Officer of Gastar Exploration USA, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.4†		Certification of Principal Financial Officer of Gastar Exploration USA, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1††		Certification of Principal Executive Officer of Gastar Exploration Ltd. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. .

32.2††		Certification of Principal Financial Officer of Gastar Exploration Ltd. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.3††		Certification of Principal Executive Officer of Gastar Exploration USA, Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.4††		Certification of Principal Financial Officer of Gastar Exploration USA, Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1†		Unaudited Pro Forma Combined Financial Information.

101.INS††		XBRL Instance Document

Table of Contents



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

____________________________________


†	Filed herewith.


††	Furnished herewith.


*	Pursuant to Item 601(b)(2) of Regulation S-K, the schedules and similar attachments to Exhibits 2.1, 2.2 and 2.3 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.

Table of Contents

SIGNATURES

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



		GASTAR EXPLORATION LTD.

Date:	November 4, 2013	By:	/S/ J. RUSSELL PORTER
			J. Russell Porter
			President and Chief Executive Officer
			(Duly authorized officer and principal executive officer)



Date:	November 4, 2013	By:	/S/ MICHAEL A. GERLICH
			Michael A. Gerlich
			Senior 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:	November 4, 2013	By:	/S/ J. RUSSELL PORTER
			J. Russell Porter
			President
			(Duly authorized officer and principal executive officer)



Date:	November 4, 2013	By:	/S/ MICHAEL A. GERLICH
			Michael A. Gerlich
			Secretary and Treasurer
			(Duly authorized officer and principal financial and accounting officer)

Table of Contents

EXHIBIT INDEX



Exhibit Number		Description
2.1		Second Amendment of Purchase and Sale Agreement, dated as of June 27, 2013, but effective as June 5, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated herein by reference to Exhibit 2.1 of the Company's Current Report on Form 8-K dated July 3, 2013. File No. 001-32714).

2.2		Third Amendment of Purchase and Sale Agreement, dated as of July 11, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated herein by reference to Exhibit 2.1 of the Company's Current Report on Form 8-K dated July 17, 2013. File No. 001-32714).

2.3		Purchase and Sale Agreement, dated as of July 2, 2013, by and among Newfield Exploration Mid-Continent Inc. and Gastar Exploration USA, Inc. (incorporated herein by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K dated August 12, 2013. File. No. 001-32714).

2.4		Fourth Amendment of Purchase and Sale Agreement, dated July 31, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated herein by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K dated August 5, 2013. File. No. 001-32714).

2.5		Fifth Amendment of Purchase and Sale Agreement, dated August 29, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated herein by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K dated September 3, 2013. File. No. 001-32714).

2.6*		Purchase and Sale Agreement, dated September 4, 2013, by and among Gastar Exploration USA, Inc., Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P. (incorporated herein by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K dated October 28, 2013. File. No. 001-32714).

2.7		Sixth Amendment of Purchase and Sale Agreement, dated September 20, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated herein by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K dated September 23, 2013. File. No. 001-32714).

2.8		Letter Agreement to Purchase and Sale Agreement, dated September 30, 2013, by and among Gastar Exploration Texas, LP, Gastar Exploration USA, Inc. and Cubic Energy, Inc. (incorporated herein by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K dated October 4, 2013. File. No. 001-32714).

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).

Table of Contents



3.8		Certificate of Designation of Rights and Preferences of 10.75% Series B Cumulative Preferred Stock (incorporated by reference to Exhibit 4.3 of Gastar Exploration USA, Inc.’s Form 8A filed on October 31, 2013).

10.1		Waiver, Agreement and Amendment No. 1 to Second Amended and Restated Credit Agreement, dated as of July 31, 2013, among Gastar Exploration USA, Inc., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and Issuing Lender, and the Lenders named therein (incorporated herein by reference to Exhibit 10.3 of the Company's Quarterly Report on Form 10-Q dated August 5, 2013. File No. 001-32714).

10.2		Agreement and Amendment No. 2 to Second Amended and Restated Credit Agreement, dated as of October 18, 2013, among Gastar Exploration USA, Inc., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and Issuing Lender, and the Lenders named therein (incorporated herein by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K dated October 22, 2013. File No. 001-32714).

31.1†		Certification of Principal Executive Officer of Gastar Exploration Ltd. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2†		Certification of Principal Financial Officer of Gastar Exploration Ltd. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.3†		Certification of Principal Executive Officer of Gastar Exploration USA, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.4†		Certification of Principal Financial Officer of Gastar Exploration USA, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1††		Certification of Principal Executive Officer of Gastar Exploration Ltd. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. .

32.2††		Certification of Principal Financial Officer of Gastar Exploration Ltd. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.3††		Certification of Principal Executive Officer of Gastar Exploration USA, Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.4††		Certification of Principal Financial Officer of Gastar Exploration USA, Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1†		Unaudited Pro Forma Combined Financial Information.

101.INS††		XBRL Instance Document

101.SCH††		XBRL Taxonomy Extension Schema Document

101.CAL††		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF††		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB††		XBRL Taxonomy Extension Label Linkbase Document

101.PRE††		XBRL Taxonomy Extension Presentation Linkbase Document

___________________________________


†	Filed herewith.


††	Furnished herewith.


*	Pursuant to Item 601(b)(2) of Regulation S-K, the schedules and similar attachments to Exhibits 2.1, 2.2 and 2.3 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.