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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2007

OR

FOR THE TRANSITION PERIOD FROM              TO             .

Commission file number 001-32714

GASTAR EXPLORATION LTD.

(Exact name of registrant as specified in its charter)

(713) 739-1800

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  ¨    Accelerated filer  ¨    Non-accelerated filer  x

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

Total number of common shares, no par value per share, as of November 7, 2007 was 208,203,570.

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GASTAR EXPLORATION LTD.

QUARTERLY REPORT ON FORM 10-Q

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2007

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Unless otherwise indicated or required by the context, (i) “we”, “us”, and “our” refer to Gastar Exploration Ltd. and its subsidiaries and predecessors, (ii) “GeoStar Acquisition” refers to our June 2005 acquisition from GeoStar Corporation (“GeoStar”) of additional reserves and working interests in the Powder River Basin and in East Texas, (iii) “senior secured notes” refers to our $73.0 million principal amount of senior secured notes issued in 2005, (iv), “convertible senior debentures” refers to our $30.0 million principal amount of 9.75% convertible senior unsecured debentures, (v) “unsecured notes” refer to our $3.25 million principal amount of 10% subordinated unsecured notes payable, (vi) “warrants” refers to the warrants to purchase common shares issued to investors in connection with certain financing transactions or to our placement agents in connection with the offering of convertible senior debentures and certain other subordinated notes as partial compensation for their services, (vii) all dollar amounts appearing in this Form 10-Q are stated in United States dollars unless specifically noted in Canadian dollars (“CDN$”), and (viii) all financial data included in this Form 10-Q has been prepared in accordance with accounting principles generally accepted in the United States of America.

General information about us can be found on our website at www.gastar.com. The information on our website is neither incorporated into, nor part of, this report. Our Annual Reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, 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 United States Securities and Exchange Commission (“SEC”). Information is also available at www.sec.gov for United States filings and on SEDAR at www.sedar.com for Canadian filings.

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

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

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

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

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

(Unaudited)

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

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

The accounting policies followed by Gastar Exploration Ltd. (the “Company”) are set forth in the notes to the Company’s audited consolidated financial statements in its Annual Report on Form 10-K for the year ended December 31, 2006. Additionally, refer to the notes to those financial statements for additional details of the Company’s financial condition, results of operations and cash flows. All material items included in those notes have not changed except as a result of normal transactions in the interim or as disclosed within this report. The accompanying interim condensed consolidated financial statements have not been audited by independent accountants but, in the opinion of management, reflect all normal and recurring adjustments considered necessary for a fair presentation of the financial position and results of operations. The results of operations for the three and nine months ended September 30, 2007 are not necessarily indicative of results to be expected for the full year.

The condensed consolidated financial statements of the Company are presented in United States (“U.S.”) dollars unless otherwise noted and have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). The preparation of financial statements in conformity with US 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 condensed consolidated financial statements include the accounts of the Company and the consolidated accounts of all its subsidiaries. The entities included in these consolidated accounts are all wholly owned. All significant intercompany accounts and transactions have been eliminated in consolidation.

Certain information provided for the prior periods has been reclassified to conform to the presentation adopted in 2007.

New Accounting Pronouncements

Accounting for Uncertainty in Income Taxes. Effective January 1, 2007, the Company adopted SFAS Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of SFAS Statement No. 109” (“FIN 48”). This interpretation provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS No. 109, “Accounting for Income Taxes”. FIN 48 requires a company to evaluate whether the tax position taken by a company will more likely than not be sustained upon examination by the appropriate taxing authority. It also provides guidance on how a company should measure the amount of benefit that a company is to recognize in its financial statements. FIN 48 also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. There was no material effect of adopting FIN 48 on the Company’s financial statements.

Fair Value Measurements. In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), which addresses how companies should measure fair value when companies are required to use a fair value measure for recognition or disclosure purposes under generally accepted accounting principles (“GAAP”). As a result of SFAS No. 157, there is now a common definition of fair value to be used throughout GAAP. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. Although the disclosure requirements may be expanded where certain assets or liabilities are fair valued such as those related to stock compensation expense and hedging activities, the Company is evaluating the potential financial statement impact of SFAS No. 157.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

2. Drilling Advances

Drilling advances represent the Company’s proportionate share of planned authorized drilling expenditures paid to the operator and an advance payment to a drilling contractor. Pursuant to the contract, the advance payment is being amortized over the three-year term of the drilling contract agreement on a straight line basis as an increase to capitalized natural gas and oil property costs.

3. Property and Equipment

The amount capitalized as natural gas and oil properties was incurred for the purchase and development of various properties in the states of Texas, Wyoming, West Virginia and Montana in the United States and in New South Wales and Victoria in Australia. The following schedule represents natural gas and oil property costs by country:

As of September 30, 2007, unproved properties not being amortized included United States drilling in progress costs of $907,000.

For the nine months ended September 30, 2007, the Company recorded an impairment of $28.5 million, which was reported in the second quarter of 2007 utilizing a weighted average natural gas price of $5.72 per Mcf, held constant. For the nine months ended September 30, 2006, the Company recorded an impairment of $37.3 million, which was reported in the first quarter of 2006 utilizing a weighted average natural gas price of $5.79 per Mcf, held constant.

In May 2007, the Company sold a portion of its undeveloped natural gas and oil acreage in the Hilltop area of East Texas for approximately $68.2 million, before transaction costs of approximately $1.4 million, resulting in a gain on sale of $38.9 million. The Company follows the full cost method of accounting, which typically does not allow for gain on sale recognition involving less than 25% of the reserves in a given cost center. Reducing the United States full cost pool by the $66.8 million in net sales proceeds would have resulted in an approximate 39% reduction in capitalized cost with no change in proved reserves, thus “significantly altering” the relationship of capitalized costs to proved reserves. The significant reduction in the full cost pool was deemed to be an “out-of-the-ordinary situation”, and the Company determined that gain recognition on the sale of unproven property was the proper accounting treatment.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

4. Long-Term Debt

The following summarizes the Company’s long-term debt as of the dates indicated:

Senior Secured Notes

On June 17, 2005, the Company issued $63.0 million in principal amount of senior secured notes. On September 19, 2005, the Company issued to the holders of these notes an additional $10.0 million of senior secured notes on substantially the same terms as the original June 2005 private placement. The senior secured notes are secured by substantially all of the Company’s assets, bear interest payable quarterly equal to the sum of the three-month LIBOR rate at the beginning of the current quarter plus 6.0% (11.23% at October 1, 2007) and mature five years and one day from the date of issuance. The senior secured notes are redeemable in whole or in part prior to maturity at the Company’s option at any time upon payment of the principal and accrued and unpaid interest plus a premium of 5% until the third anniversary of issuance, 4% from the third anniversary to the fourth anniversary and 3% from the fourth anniversary until the day before maturity. Redemption at the Company’s option is not permitted following the public announcement of certain pending, proposed or intended change of control transactions.

In connection with the senior secured notes issuances, the Company agreed to issue to the note holders, for no additional consideration, common shares in increments valued at CDN$4.5 million with respect to the $63.0 million of senior secured notes and additional common shares in increments valued at CDN$714,286 with respect to the $10.0 million of senior secured notes at closing and on each of the six, twelve and eighteen-month anniversaries of the closing date, valued on a five-day weighted average trading price immediately prior to the date of issuance. The Company initially recorded a liability of $17.0 million related to common shares to be issued and a corresponding amount recorded as a debt discount to be accreted to interest expense using the effective interest method. The Company also incurred an estimated $3.0 million of direct financing costs for legal fees and fees paid to an agent as deferred charges and are amortizing these costs over the term of the senior secured notes. As of September 30, 2007, the Company had no further obligation to issue additional common shares under the senior secured notes.

Under the senior secured notes, the PV(10) valuation is to be based on a reserve report utilizing constant pricing based on the lower of current natural gas and oil prices, adjusted for area basis differentials, or $6.00 per Mcf of natural gas and $40.00 per barrel of oil. As of September 30, 2007, proved reserves PV(10) (“1P (PV10)” to net senior secured notes debt must be a minimum of 1.5:1, and it increases to 2.0:1 on the third anniversary date and for all test periods thereafter until maturity. Utilizing the reserve pricing criteria above, the proved plus probable reserves PV(10) (“2P PV10)” to net senior secured notes debt reserve ratio is a minimum of 3.0:1, and it increases to 3.5:1 on the third anniversary and for all test periods thereafter until maturity. We must maintain compliance with the reserve ratio covenants at all future quarterly and annual covenant determination dates or be subject to mandatory principal redemptions under certain conditions. At September 30, 2007, the Company was in compliance with the debt covenant. The senior secured notes prohibit us from issuing any debt senior or pari passu to the senior secured notes and may limit the Company’s ability to borrow subordinated funds and payment of dividends.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The Company’s bank deposit accounts are subject to account agreements in favor of its senior lenders that allow the senior lenders to take certain actions under specific circumstances to pay interest and/or principal outstanding related to the senior secured notes.

Convertible Senior Debentures

In November 2004, the Company issued $30.0 million aggregate principal amount of convertible senior unsecured debentures. The convertible senior debentures have a term of five years, bear interest at 9.75% per annum, payable quarterly and mature on November 20, 2009. The convertible senior debentures are convertible by the holders into common shares at a conversion price of $4.38 per share. The convertible senior debentures may be redeemed at any time by the Company at a redemption price equal to par plus accrued and unpaid interest; provided that, the volume weighted average trading price of the common shares of the Company, for at least 20 trading days in any consecutive 30-day period, equals or exceeds $5.69, representing 130% of the final conversion price of $4.38.

Subordinated Unsecured Notes Payable

In July 2004, the Company completed a $3.25 million subordinated unsecured note financing. The unsecured notes mature between April 2009 and September 2009, bear interest at 10% per annum and became callable by the Company in July 2006 at 108% of the principal amount. The call premium reduced to 105% in July 2007 and will reduce to 101% in July 2008.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

5. Interest Expense

The following table summarizes the Company’s interest expense components for the periods indicated:

6. Share Based Compensation

Share-Based Compensation Plans

2002 Stock Option Plan. The Company’s 2002 Stock Option Plan was approved and ratified by the Company’s shareholders in July 2002. It authorizes the Company’s Board of Directors to issue stock options to directors, officers, employees and consultants of the Company and its subsidiaries to purchase a maximum of 25.0 million common shares. Stock option grant expirations vary between five and ten years. The vesting schedule has varied from two years to four years but generally has occurred over a four-year period at 25% per year beginning on the first anniversary date of the grant. Stock options issued pursuant to the Company’s 2002 Stock Option Plan have an exercise price determined by the Board of Directors, but that exercise price cannot be less than the market price on the date immediately prior to the date of grant as reported by any stock exchange on which the Company’s common shares are listed. If a stock option granted under the Company’s 2002 Stock Option Plan expires or terminates for any reason in accordance with the terms of the Company’s Stock Option Plan, the unpurchased common shares subject to that stock option become available for other stock option grants.

In April 2004, the Board of Directors amended the provisions of the Company’s 2002 Stock Option Plan to specifically incorporate a provision to provide for stock options to be exercised on a cashless basis, whereby the Company issues to the optionee the number of common shares equal to the stock option exercised, less the number of common shares which when multiplied by the market price at the date of exercise equals the aggregate exercise price for all of the common shares exercised. As of September 30, 2007, stock option grants covering the issuance of 10,173,750 common shares were outstanding under the 2002 Stock Option Plan.

2006 Gastar Long-Term Stock Incentive Plan. On June 1, 2006, the Company’s shareholders approved the 2006 Gastar Long-Term Stock Incentive Plan. The 2006 Gastar Long-Term Stock Incentive Plan authorizes the Company’s Board of Directors to issue stock options, stock appreciation rights, bonus stock awards and any other type of award established by the Committee which is consistent with the Plan’s purposes to directors, officers and employees of the Company and its subsidiaries covering a maximum of 5.0 million common shares. The contractual life and vesting period for a grant will be determined by the Board of Directors at the time grant is awarded. The vesting period for restricted common stock grants during the nine months ended September 30, 2007 is over four years, with one-third vesting on the second, third and fourth anniversaries of the date of grant. As of September 30, 2007, grants covering the issuance of 1,105,000 restricted common shares were outstanding under the 2006 Gastar Long-Term Stock Incentive Plan.

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(Unaudited)

Determining Fair Value under SFAS No. 123R

In determining fair value for stock option grants pursuant to SFAS No. 123R, the Company utilized the following assumptions:

Valuation and Amortization Method. The Company estimates the fair value of share-based awards granted using the Black-Scholes-Merton valuation model. The fair value of all awards is expensed using the “graded-vesting method”, which recognizes compensation costs over the requisite service period for each separately vesting tranche of an award as though the award were, in substance, multiple awards.

Expected Life. The expected life of awards granted represents the period of time that stock options are expected to be outstanding. The Company determined the expected life using the “simplified method” resulting in a 6.25-year expected life in accordance with Staff Accounting Bulletin No. 107 for all stock options issued with a four-year vesting period and a ten-year grant expiration. Using the simplified method, stock options that have been issued with two and three-year vesting periods and having a ten-year expiration have an expected life of 5.75 and 6.0 years, respectively. Prior to October 2005, the Company’s stock options had a five-year expiration and expected life.

Expected Volatility. Using the Black-Scholes-Merton valuation model, the Company estimates the volatility of its common shares at the beginning of the quarter in which the stock option is granted.

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

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

Expected Forfeitures. In 2006, the Company began using a forfeiture rate of 5% in determining initial compensation expense, based on forfeitures of all unvested stock option as a percentage of all stock option grants calculated at the beginning of the year. The estimated forfeiture rate for 2007 is also 5.0%.

The fair value of each stock option grant is estimated on the date of grant using the Black-Scholes-Merton valuation pricing model. During the nine months ended September 30, 2007 and 2006, the Company granted 828,000 and 4,790,000 stock options, respectively. A summary of the assumptions for stock options granted during the nine months ended September 30, 2007 and 2006 are as follows:

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(Unaudited)

Stock Option Activity

The following table summarizes the changes and stock option exercise prices for stock options for the nine months ended September 30, 2007:

As of September 30, 2007, there was no aggregate intrinsic value for outstanding stock options, and the remaining weighted average contractual life of outstanding stock options was 5.1 years. As of September 30, 2007, there was no aggregate intrinsic value for exercisable stock options, and the remaining weighted average contractual life of exercisable stock options was 3.5 years. As of September 30, 2007, the total fair value of exercisable stock options was $5.0 million. The following table summarizes certain information about the fair and intrinsic value of stock options for the periods indicated:

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(Unaudited)

The following table summarizes the range of exercise prices for stock options outstanding and exercisable as of September 30, 2007:

Restricted Share Activities

The following table summarizes the changes and grant date prices for restricted common share grants for the nine months ended September 30, 2007:

The following table summarizes the range of grant dates and grant date prices for restricted common shares outstanding and unvested as of September 30, 2007:

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(Unaudited)

As of September 30, 2007, the remaining weighted average contractual life of unvested restricted common shares was 3.8 years. As of September 30, 2007 and 2006, the total value and weighted average value per restricted common shares outstanding were as follows:

Stock-Based Compensation

For the three months ended September 30, 2007 and 2006, the Company recorded stock-based compensation expense for stock options and restricted common shares granted using the fair-value method of $898,000 and $1.4 million, respectively. For the nine months ended September 30, 2007 and 2006, the Company recorded stock-based compensation expense for stock options and restricted common shares granted using the fair-value method of $3.1 million and $2.6 million, respectively. All stock based compensation costs were expensed and not tax effected, as the Company currently records no income tax expense. All common shares issued upon exercise or vesting are reserved and non-assessable.

At September 30, 2007, the Company had unvested stock options to purchase 5,646,250 common shares with a weighted average grant date fair value of $1.21 per common share and 1,105,000 restricted common shares outstanding having a weighted average grant date value of $2.15 per common share. As of September 30, 2007, the Company had approximately $5.1 million of total unrecognized compensation cost related to unvested stock options and restricted common shares, which is expected to be amortized over the following periods:

7. Commodity Hedging Contracts

In the third quarter of 2007, the Company entered into a costless collar transaction with a counterparty. The following transaction was outstanding with associated notional volumes and contracted floor and ceiling prices that represent hedge prices at Inside FERC Colorado Interstate Gas Rocky Mountains (“IFERC CIG Rocky Mountains”) at September 30, 2007:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The Company’s current cash flow hedge position is with a counterparty that is a subsidiary of major United States financial institution. As of September 30, 2007, the Company had a $1.0 million collateral position with the counter party secured by a Company cash collateralized letter of credit. As of September 30, 2007, the Company recorded a short term derivative liability of $65,000 related to the difference between hedged commodity prices and market prices on hedged volumes as of September 30, 2007. All of the Company’s derivative instruments have been designated as hedging instruments.

8. Loss per Share

In accordance with the provisions of SFAS No. 128, “Earnings per Share”, basic earnings per share is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings per share is computed based upon the weighted average number of common shares 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.

9. Income Taxes

On January 1, 2007, the Company adopted FIN 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109”, regarding accounting for uncertainty in tax positions. The Company remains subject to examination of income tax filings in the United States and various state jurisdictions for the 2000-2006 tax years. The Company has also determined that it is subject to examination in various foreign jurisdictions for all prior periods due to the Company’s continued loss position in such jurisdictions. Within each of these jurisdictions, the material tax positions were examined under the more-likely-than-not guidance provided by FIN 48. If interest and penalties were to be assessed, the Company would charge interest to interest expense, and penalties to general and administrative expense.

As a result of the FIN 48 assessment, the Company concluded that it has not taken any uncertain tax positions on any of its open tax returns that would materially distort the Company’s financial statements. There was no material cumulative effect of adopting FIN 48 on the Company’s financial statements as of January 1, 2007.

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(Unaudited)

10. Commitments and Contingencies

Litigation

The Company is party to various litigation matters arising out of the normal course of business. The ultimate outcome of the matters discussed below cannot presently be determined, nor can the liability that could potentially result from an adverse outcome be reasonably estimated at this time. The Company does not expect that the outcome of these proceedings will have a material adverse effect on its financial position, results of operations or cash flow. The more significant litigation matters are summarized below.

Estate of Virgil Sparks and Oil Wells of Kentucky, Inc. vs. First Sourcenergy Group Inc. (now Gastar Exploration New South Wales, Inc. (“GENSW”)) and GeoStar Corporation Arbitration. In August 2002, GENSW, a wholly owned Company subsidiary, was a named party to this arbitration proceeding. The dispute involves historical dealings with the development of an Authority to Prospect (“ATP”) Area in Queensland, Australia, as well as an ancillary agreement. GENSW and GeoStar moved to dismiss the arbitration on the grounds of a claimed prior settlement and release agreement. The request for arbitration dismissal was granted in favor of GENSW and GeoStar on October 2, 2007.

Navasota Resources L.P. (“Navasota”) vs. First Source Texas, Inc. (now Gastar Exploration Texas, Inc.), First Source Gas L.P. (now Gastar Exploration Texas LP) and Gastar Exploration Ltd. (Cause No. 0-05-451) District Court of Leon County, Texas 12^th Judicial District. This lawsuit contends that the Company breached Navasota’s preferential right to purchase 33.33% of the Company’s interest in certain natural gas and oil leases located in Leon and Robertson Counties and sold to Chesapeake Energy Corporation pursuant to a transaction closed November 4, 2005. The preferential right claimed is under an operating agreement dated July 7, 2000. The Company contends, among other things, that Navasota neither properly nor timely exercised any preferential right election it may have had with respect to the inter-dependent Chesapeake transaction. In July 2006, the District Court of Leon County, Texas issued a summary judgment in favor of the Company and Chesapeake. Navasota filed a Notice of Appeal to the Tenth Court of Appeals in Waco. All parties have filed their respective briefs, and oral argument was heard on September 26, 2007. The Company intends to continue to vigorously defend itself against this claim.

Gastar Exploration Texas LP vs. John E. McFarlane, et al (Cause No. 0-06-161) 87^th Judicial District Court of Leon County, Texas. This suit was filed seeking to quiet title to mineral interests under an oil and gas lease dated December 4, 2003, covering approximately 2,598 gross acres (the “Lease”). John E. McFarlane and certain other family members contend that mineral interests that were part of the Estate of Fay Watson McFarlane are not subject to the Lease. The Company claims that these mineral interests are in fact subject to the Lease. Various motions for summary judgment have been filed by the McFarlanes, which the trial court has denied. A day long mediation of this lawsuit occurred on August 24, 2007, but the parties were unable to settle this matter. The Company will continue to vigorously pursue this claim.

Burning Rock Energy, LLC, et al (“Burning Rock”) vs. First Sourcenergy Wyoming, Inc. (now Gastar Exploration USA, Inc.), et al. Burning Rock contends in this 2006 lawsuit and other related lawsuits that the Company and the operator of certain Wyoming natural gas properties were obligated under a January 1, 2004 Exchange Agreement to make lease maintenance payments on certain leases to be assigned to Burning Rock under the Exchange Agreement. At December 31, 2006, the Company’s present value, discounted at 10%, of the leases in dispute was approximately $742,000. In April 2007, the Company assigned its interest in the disputed leases for a full release from this litigation matter.

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(Unaudited)

The Company was named in several lawsuits by third parties primarily relating to actions taken with respect to Company common stock by GeoStar Corporation:

Larry McNiell v. GeoStar Corporation, First Source Wyoming, Inc. and Gastar Exploration Ltd. (Case No. 2:06cv00911 TS); In the United States District Court for the District of Utah, Central Division. This lawsuit was filed by Larry McNiell, as Plaintiff, seeking damages arising out of certain agreements entered into with First Source Wyoming, Inc. (“FSW”), a subsidiary of GeoStar Corporation, and GeoStar Corporation. The Plaintiff asserted breaches of contract against, and conversion by, GeoStar and FSW for their alleged failures to make required payments, deliver required Company shares without restrictions and cover certain Plaintiff loans. The Plaintiff asserted a cause of action for declaratory judgment against the Company asking the Court to declare that the Company cannot place restrictions on the shares owed by GeoStar to Plaintiff. On May 29, 2007, the federal court dismissed McNeill’s claims against the Company for lack of personal jurisdiction.

Roland Spongberg v. GeoStar Corporation, First Source Wyoming, Inc. and Gastar Exploration Ltd., and Does 1 through 100 (Case No. VC046736); In the Superior Court of California, Los Angeles County. This lawsuit was filed June 1, 2006 and arose out of Roland Spongberg’s investment in Coalbed Methane Drilling Program sponsored by First Source Wyoming, Inc., a GeoStar subsidiary (“FSW”). This claim is primarily related to GeoStar actions and Company common shares claimed to be owed to Spongberg by GeoStar. In June 2007, Spongberg dismissed his claims against the Company with prejudice.

Spencer D. Plummer, III v. GeoStar Corporation, Classic Star LLC, Gastar Exploration, Ltd., Thom Robinson, Tony Ferguson, and John W. Parrott; In the United States District Court of Utah, Central Division (Case No. 2:07-CV-00409). This lawsuit was filed on May 24, 2007 initially in Utah state court by Spencer Plummer, or the Plaintiff, in which he asserts breaches of his Employment Agreement and subsequent Termination Agreement (the “Agreements”) with his employer, Classic Star, a subsidiary of GeoStar. The Plaintiff claims that he has not received benefits promised under such Agreements, including 699,249 shares of Company stock. The Company is not a party to the Agreements on which Plaintiff’s claims are expressly based; however, the Company and Plaintiff are parties to a Stock Option Agreement on which Plaintiff claim to Company stock is partially based. The Company filed an Answer and Motion to Dismiss for lack of personal jurisdiction in Utah and for Plaintiff’s failure to state a claim upon which relief can be granted. Plaintiff filed a Motion to Remand to state court, and on September 5, 2007, the Court denied Plaintiff’s Motion to Remand. The Company awaits the Court’s ruling on its Motion to Dismiss.

Arbitration and Litigation with GeoStar Corporation and Affiliates

Arbitration against GeoStar and Affiliates. On October 18, 2006, in connection with 10 wells to be drilled in Victoria, Australia on the jointly owned EL 4416 exploration license operated by GeoStar, the Company sent a letter to GeoStar demanding the arbitration of certain disputed issues and interpretations under a Participation and Operating Agreement (“POA”) with GeoStar and its subsidiaries. Among other items, the claims the Company presented for resolution in arbitration include claims relating to GeoStar’s demands for cash calls under the POA while simultaneously asserting that certain provisions of the POA, including overhead reimbursement rates, need to be renegotiated on terms that the Company believes are not reasonable or within industry standards. The Company has also requested that GeoStar’s Australian subsidiary provide a record title assignment of the Company’s beneficial interests in EL 4416, the exploration license in the Gippsland Basin property in Victoria, Australia. GeoStar contends that the Company is not entitled to the record title assignment. The Company’s former Chairman of the Board is a major shareholder and President of GeoStar. The arbitrators have not yet been appointed, though that process is currently underway. No hearing date for the arbitration has been scheduled. As discussed below, GeoStar denies that the disputes raised in the arbitration proceeding are subject to arbitration and has recently filed a lawsuit in Michigan federal court, seeking, among other things, to enjoin the arbitration.

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

GeoStar Corporation and West Virginia Gas Corporation v. Gastar Exploration Ltd. and J. Russell Porter. On July 27, 2007, the Company was served with a lawsuit filed by GeoStar and one of its affiliates, West Virginia Gas Corporation, in federal court in Saginaw, Michigan. The lawsuit relates to the arbitration referenced above and issues raised in that arbitration, as well as other issues. GeoStar is asserting a broad range of claims against the Company and its current chief executive officer, J. Russell Porter. The Company disputes the allegations in the Michigan lawsuit and has filed motions in the Michigan lawsuit to dismiss certain of the claims on jurisdictional grounds, to dismiss other claims for failure to state a claim on which relief may be granted, and to stay certain of the claims pending the arbitration proceedings referenced above.

GeoStar claims in the Michigan lawsuit that the POA was cancelled effective January 1, 2005, and that the parties have operated under oral contracts since that date. GeoStar alleges that the issues in the Company’s arbitration proceeding arose under the alleged oral contracts, not the POA, and that the Company’s claims asserted in the arbitration therefore are not subject to arbitration under the arbitration provision in the POA. GeoStar seeks an order from the court enjoining the arbitration from going forward.

GeoStar also claims that the Company has breached the alleged oral contracts by allegedly failing to pay joint interest billings, authorizations for expenditures, and cash calls relating to operations or proposed operations on EL 4416 in Australia and West Virginia properties, in an unspecified amount exceeding $75,000. GeoStar also claims that the Company has breached alleged agreements to reimburse GeoStar for various payments and services allegedly performed by GeoStar and its personnel and paid on behalf of the Company by GeoStar. GeoStar claims that the amounts of the payments and the value of the services exceed $10 million. GeoStar alternatively alleges that if there was no contract covering those payments and services, it allegedly is entitled to reimbursement on equitable principles. GeoStar also seeks a declaration that the Company does not own rights in EL 4416.

GeoStar also asserts claims in the Michigan lawsuit relating to Texas properties that were the subject of Purchase and Sale Agreements entered into in 2005, under which the Company acquired the interests of GeoStar-affiliated entities in properties in Texas. Specifically, GeoStar claims that the Company breached the Purchase and Sale Agreements by failing to provide information in connection with contingent “Look Back” payments under provisions of the Purchase and Sale Agreements, and by failing to make payments allegedly due to GeoStar under the Look-Back provisions, arising out of alleged changes in reserves following the sale of the Texas properties in June 2005. GeoStar is seeking an amount in excess of not less than 10 million shares of Company common stock or $10 million under the Look Back provisions. GeoStar also claims that the Company failed to timely comply with provisions of the Purchase and Sale Agreements relating to the drilling of 20 wells on the properties conveyed under the Purchase and Sale Agreements and by failing to drill and test at least two wells in the Travis Peak formation in Texas, allegedly entitling GeoStar to unspecified damages and a farm-in interest allegedly giving GeoStar the right to drill, complete, and operate wells in the Travis Peak formation on certain acreage. The Company asserts that it has not breached the Purchase and Sale Agreements and that it has satisfied its drilling and testing obligations with respect to the Travis Peak wells. Further, the Company assets that it has timely furnished all Look-Back information and that no 2006 Look Back payments are owed to GeoStar.

GeoStar and West Virginia Gas Corporation, an affiliate of GeoStar, also assert claims against the Company and its current chief executive officer, alleging that the Company and its current chief executive officer tortiously interfered with an alleged contract between GeoStar and with certain West Virginia individuals and entities. According to the lawsuit, these individuals and entities allegedly promised to give their oil, gas, and coalbed methane opportunities in West Virginia and Pennsylvania to GeoStar. GeoStar and West Virginia Gas Corporation alleged that Gastar and its chief executive officer caused those individuals and entities to establish and use new business entities to allegedly conceal opportunities from West Virginia Gas Corporation and to funnel them to the Company, the Company’s chief executive officer and the West Virginia individuals and entities. The Company intends to vigorously defend itself against the plaintiffs’ claims in the Michigan litigation.

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Gastar Exploration, Ltd., Gastar Exploration Texas, Inc., f/k/a First Texas Development, Inc., Gastar Exploration Texas LLC, f/k/a Bossier Basin, LLC, and Gastar Exploration Texas LP, f/k/a First Source Gas, LP v. GeoStar Corporation, First Source Texas, Inc., First Source Bossier, LLC, and First Texas Gas, LP. In July 2007, the Company filed a lawsuit in Robertson County, Texas against GeoStar and affiliates seeking relief in connection with the failure by GeoStar and its affiliates to execute formal assignments of certain leases that were omitted from the schedule of leases attached to the assignments executed by GeoStar affiliates in June 2005 pursuant to Purchase and Sale Agreements covering Texas properties of GeoStar and its affiliates. The lawsuit asks the court to decree that in the transaction evidenced by the Purchase and Sale Agreements, affiliates of the Company acquired title to all properties in Texas in which GeoStar and its affiliates owned an interest and that GeoStar and its affiliates are obligated to execute formal assignments with regard to all such leases. GeoStar and one of its affiliates have filed a challenge to the Texas court’s jurisdiction. All of the defendants have filed pleadings contending that this litigation should be stayed pending the Michigan litigation discussed above. The defendants also have generally denied the allegations made in the lawsuit. The case is in its early stages.

Gastar Exploration Ltd., Gastar Exploration USA, Inc. f/k/a First Sourcenergy Wyoming Inc., Gastar Exploration New South Wales, Inc., f/k/a First Sourcenergy Group, Inc., Gastar Exploration Victoria, Inc. f/k/a First Sourcenergy Victoria, Inc., Gastar Exploration Texas, Inc., f/k/a First Texas Development, Inc., Gastar Exploration Texas LLC, f/k/a Bossier Basin, LLC, and Gastar Exploration Texas LP, f/k/a First Source Gas, LP v. GeoStar Corporation. In July 2007, the Company and affiliates filed a lawsuit in the District Court of Harris County, Texas against GeoStar in connection with GeoStar’s failure to deliver to the Company and its affiliates the corporate records of the Company and to its affiliates that have been retained by GeoStar. Representatives of the Company and its affiliates previously demanded return of the corporate records retained by GeoStar, but GeoStar failed to return the records. The lawsuit asks the court to decree that the Company and its affiliates are entitled to possession of the corporate records and order their return to the Company and its affiliates. The lawsuit also seeks recovery of actual and punitive damages, costs, and attorney’s fees. GeoStar has now delivered records that are the subject of this litigation to the Company, and the Company is in the process of determining the completeness of those records. The case remains pending.

Gastar Exploration, Ltd., Gastar Exploration Texas, Inc., f/k/a First Texas Development, Inc., Gastar Exploration Texas LLC, f/k/a Bossier Basin, LLC, and Gastar Exploration Texas LP, f/k/a First Source Gas, LP v. GeoStar Corporation, First Source Texas, Inc., First Source Bossier, LLC, and First Texas Gas, LP. In August 2007, the Company and certain affiliates filed a second lawsuit in Robertson County, Texas, seeking a declaratory judgment that the Company and its affiliates have complied with the Look-Back provisions of the Texas Purchase and Sale Agreements that are the subject of the other Robertson County, Texas lawsuit referenced above, that the Company and its affiliates have complied with the provisions of the Texas Purchase and Sale Agreements relating to the drilling of wells, and that GeoStar and its affiliates hold no farm-in interest in properties owned by the Company’s affiliates. The defendants have been served with the lawsuit but have not yet filed responsive pleadings.

GeoStar Look Back Developments. The Purchase and Sale Agreements between GeoStar and the Company relating to certain Texas properties acquired by the Company in 2005 (the “PSAs”) contain a “Look Back” provision that is the subject of claims in two of the previously described lawsuits with GeoStar. As of November 6, 2007, GeoStar (1) had not formally responded to the Company’s June 30, 2006 and 2007 Look Back analyses that were based on reserve reports prepared by Netherland Sewell & Associates, Inc. (“NSA”) and (2) had not provided a qualified independent reserve analysis prepared on a consistent basis utilizing the Securities and Exchange Commission (“SEC”) and Society of Petroleum Engineers (“SPE”) definitions disputing the Company’s June 30, 2006 and 2007 Look Back analyses. On November 1, 2007, however, GeoStar informed the board of directors of the Company that it intends to submit a reserve report for purposes of the Look Back analyses showing that the gross reserves attributable to the Company’s leasehold interests are substantially greater than those reflected in the NSA reserve reports on which the Company’s look-back analyses were based. GeoStar informed the Company’s directors that it contends that a substantial number of shares of the Company are owed to GeoStar under the terms of the PSAs. When GeoStar provides its reserve report, the Company will review it to determine whether it is based on the required SEC and SPE guidelines, accurately reflects the respective interests of the parties and is calculated in accordance with the PSAs. The Company will also review GeoStar’s contentions relating thereto and evaluate its legal position and options.

In March 2007, the Company recorded a $5.0 million litigation settlement expense accrual related to a proposed settlement with GeoStar regarding the various GeoStar arbitration and litigation matters. The settlement proposal was never finalized.

Commitments

During 2006, the Company entered into an agreement with a drilling contractor to provide contracted drilling services in the Hilltop area of East Texas for a three-year period at agreed upon day rates. The Company made advance payments totaling $2.0 million prior to drilling rig delivery in November 2006. The advance payments are being amortized over the three-year term of the agreement. The Company is required to pay the drilling contractor a minimum of $6.3 million per year in drilling day rate fees, net of the amortization of the advance payments, during the three-year term of the agreement commencing November 2006.

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

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The following discussion and analysis should be read in conjunction with accompanying condensed consolidated financial statements and related notes included in this Form 10-Q. It contains forward looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and oil, economic and competitive conditions, regulatory changes, the impact of acquisitions, estimates of proved reserves, potential failure to achieve production from development projects, capital expenditures and other uncertainties, as well as those factors discussed in this Form 10-Q and in our Annual Report on Form 10-K for the year ended December 31, 2006, particularly in “Risk Factors” and “Cautionary Notes Regarding Forward Looking Statements”, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward looking events discussed may not occur.

Overview

We are an independent energy company engaged in the exploration, development and production of natural gas and oil in the United States and Australia. Our principal business activities include the identification, acquisition, and subsequent exploration and development of natural gas and oil properties. Our emphasis is on prospective deep structures identified through seismic and other analytical techniques as well as unconventional natural gas reserves, such as coal bed methane, or CBM. We currently are pursuing unconventional natural gas exploration in the deep Bossier play in the Hilltop area in East Texas. Our primary CBM properties are in the United States in the Powder River Basin and in the Gunnedah and Gippsland Basins of Australia.

Hilltop Area, East Texas

The majority of our activity focus has been in the deep Bossier play in the Hilltop area, located in East Texas approximately midway between Dallas and Houston in Leon and Robertson Counties, Texas. In May 2007, we sold a portion of our undeveloped natural gas and oil acreage in the Hilltop area of East Texas for approximately $68.2 million, net of transaction costs of approximately $1.4 million, resulting in a gain on sale of $38.9 million. As a result of the sale of undeveloped acreage, our post-sale acreage in East Texas is approximately 37,500 gross (16,500 net) acres.

During the nine months ended September 30, 2007, we continued our exploratory drilling program in this area, successfully drilling six gross (3.3 net) wells with a 100% success rate. To date, we have successfully completed 16 of 17 wells in East Texas, consisting of 13 deep Bossier wells and three Knowles Limestone wells. Drilling activities are continuing in the area. We are currently drilling a deep Bossier well and a horizontal Knowles Limestone well. We have recently completed a 3-D seismic survey covering all of our East Texas acreage that is providing critical information in the identification of potential drilling locations. For the nine months ended September 30, 2007, net production from the Hilltop area averaged 12.3 MMcfe per day.

Coalbed Methane – Powder River Basin, Wyoming

Our United States CBM activities are located in the Powder River Basin, where we own an approximate 40% average working interest in approximately 55,000 gross (21,900 net) acres. Our development and recompletion activities in this area provide us with a stable base of producing reserves and production.

During the nine months ended September 30, 2007, we participated in the drilling of approximately 27 gross (12.5 net) wells. An active recompletion and drilling program is continuing. For the nine months ended September 30, 2007, our net production from Powder River area averaged 4.9 MMcf per day.

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Coalbed Methane – PEL 238, Gunnedah Basin, New South Wales, Australia

We have a 35% interest in PEL 238, a CBM exploratory property covering approximately 2.2 million gross (786,000 net) acres, located in the Gunnedah Basin of New South Wales, approximately 250 miles northwest of Sydney, Australia, near the town of Narrabri. The exploration and development of our CBM assets in Australia has the potential for significant reserve and production growth.

During 2006, we participated with our joint venture partners in the drilling of eight new vertical coal seam natural gas wells drilled on approximately 40-acre spacing and in close proximity to an existing well within the Bohena Project Area. The results from the pilot production phase of the program have been positive, with the results confirming the high measured permeability of the coal and the presence of natural gas in the coal. If sustained commercial natural gas production rates are achieved, we and our joint venture partners will proceed with development of the CBM resources.

In March 2007, we announced that we and our joint venture partner had executed a Memorandum of Understanding with Macquarie Generation, a New South Wales Government-owned electricity generator, for the potential future supply of natural gas for the expansion of its Bayswater power station. Macquarie Generation is Australia’s largest electricity producer and owns and operates two coal fired power stations in the Hunter Valley – Bayswater and Liddell. A long-term natural gas supply and purchase agreement with Macquarie Generation could include up to 500 Bcf to be delivered over a 15 to 20 year period commencing in late 2010 though there is no assurance that such an agreement will ultimately be reached or that such volumes will ultimately be produced from PEL 238. In addition, a potential gas supply and purchase agreement with Macquarie Generation would serve to underpin the development of the approximately 300 kilometers of infrastructure pipeline necessary to transport gas from the PEL 238 concession to Bayswater. An additional 150 kilometers of pipeline infrastructure would be required to access the natural gas markets in the Newcastle and Sydney markets of New South Wales.

In March 2007, we announced that we and our joint venture partner had executed a Memorandum of Understanding with Macquarie Generation, a New South Wales Government-owned electricity generator, for the potential future supply of natural gas for the expansion of its Bayswater power station. Macquarie Generation is Australia’s largest electricity producer and owns and operates two coal fired power stations in the Hunter Valley—Bayswater and Liddell. We believe that a potential long-term natural gas supply and purchase agreement could cover volumes as high as 500 Bcf over a 15 to 20 year period. In addition, the potential gas supply and purchase agreement with Macquarie Generation would serve to underpin the development of the infrastructure necessary to move gas from the PEL 238 concession to the major natural gas markets in New South Wales.

Petroleum Assessment Lease 2 (PAL 2) was issued by the New South Wales Department of Primary Industries on October 30, 2007. Pal 2, in which Gastar holds a 35% interest, lies within PEL 238 and covers the existing Bohena Project Area of approximately 65,000 acres, including the Bibblewindi and Bohena Pilots with an umbilical area connecting to the Wilga Park Power Station. The assessment lease, which is intended for the area to be assessed for an eventual production lease, allows gas production from the two production pilots to be transported by a dedicated gas gathering system to the power station for electricity production and sales.

During 2008, together with Eastern Star Gas Limited (ASX:ESG), our working interest partner and license operator, we intend to expand our pilot production drilling program on the PEL 238 concession. Through our planned development program in PEL 238 considting of additional production pilot projects and core hole drilling, we are working to convert a portion of the substantial gross resource potential into additional certifiable proved and probable reserves as we move towards large scale commercial production. We anticipate the certification of proved reserves and the growth of our probable reserves as necessary to support the development of infrastructure to service growing natural gas demand in New South Wales. Contracts for the construction and such infrastructure as well as gas sales or use contracts will be required before recognition significant proved reserves in PEL 238 under SEC guidelines.

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Coalbed Methane – PEL 433-434, Gunnedah Basin, New South Wales, Australia

In July 2007, we entered into a Farm-In Agreement with our PEL 238 joint venture partners under which we will earn a 35% working interest in the PEL 433 (1.9 million gross acres, 668,700 net) and adjoining PEL 434 (1.9 million gross acres, 662,200 net). PEL 433 and 434 are located south and west of PEL 238, respectively.

Coal evaluation core hole drilling completed during the 1970s and 1980s by the New South Wales Government has already identified the distribution and thickness of the coal measures within PEL 433. The Hoskissons Coal Seam is believed to be approximately six meters thick and widely distributed within the eastern part of PEL 433. There has been no previous coal seam gas exploration and evaluation work in the area, and there is no information on gas content, gas composition or coal permeability.

Under the terms of the Farm-In Agreement, we will pay the costs of a two core-hole program and the related costs of the evaluation of the coal reservoirs intersected by the core-holes. The two core-hole drilling program commenced during July to gather this additional information to evaluate the potential of the Hoskissons Coal Seam within the Late Permian Black Jack Coal Measures.

The area believed to be the most prospective for coal seam gas development within PEL 433 underlies the Central Ranges Natural Gas Pipeline that links Dubbo with Tamworth and joins with the larger Moomba-Sydney Gas Pipeline. This gas pipeline would enable gas sales within the region and potentially to Sydney and surrounding markets.

Coalbed Methane – EL 4416, Gippsland Basin, Victoria, Australia

We have a 75% interest in the CBM rights in EL 4416, an exploration license covering approximately 1.0 million gross (750,000 net) acres property over a substantial part of the onshore portion of the Gippsland Basin of Victoria, Australia, located approximately 130 miles east of Melbourne. During 2006, we began initial long-term testing of the first of two wells completed on EL 4416. In October 2006, we pre-funded $6.5 million for a 10-well drilling program, which commenced drilling operations late 2006 and is nearing completion. The program is designed to include the establishment of two “5-spot” pilots, one incorporating two existing wells plus two wells designed to test for the presence and production potential of the coal at additional locations within the license area. In one of the two previously drilled wells, we have installed larger capacity pumps to facilitate de-watering operations.

Our activities on EL 4416 are operated by a subsidiary of GeoStar. While we believe we have good beneficial title to our interest in EL 4416, the subsidiary of GeoStar has not delivered to us a title assignment of our interest in a form to be recorded with Australian government officials. Various disputes have arisen between us and GeoStar regarding joint interest operations and billings, including the operations on EL 4416. We have sent a letter to GeoStar demanding the arbitration of these issues. This proceeding is described in Footnote 10 “Commitments and Contingencies—Litigation” to our condensed consolidated financial statements of this report.

Results of Operations

The following is a comparative discussion of the results of operations for the three and nine months ended September 30, 2007 and 2006. It should be read in conjunction with the unaudited condensed consolidated financial statements and the related notes and other information included elsewhere in this Form 10-Q.

Three Months Ended September 30, 2007 Compared to the Three Months Ended September 30, 2006.

Net loss. We reported a net loss attributable to common shares for the three months ended September 30, 2007 of $5.5 million, compared to a net loss of $7.7 million for the three months ended September 30, 2006. The net loss for the three months ended September 30, 2006 included a litigation settlement expense of $465,000.

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Revenues. Substantially all of our revenues are derived from the production of natural gas in the United States. We reported revenues of approximately $9.8 million for the three months ended September 30, 2007, up from $6.7 million for the comparable period in 2006. The 46% increase in revenues was attributable to a 66% increase in production resulting primarily from the commencement of production of natural gas from new wells in East Texas in 2007. The increase in production was partially offset by a 10% decrease in natural gas prices, primarily related to lower gas prices received for our Wyoming production.

Natural Gas and Oil Production and Average Sales Prices. Natural gas represents substantially all of our production. The table below sets forth production and sales information for the periods indicated:

Our Wyoming production constituted approximately 25% of our total natural gas production in quarter ended September 30, 2007, where we received an average natural gas price of $3.14 per Mcf. Recently, natural gas prices in the Rocky Mountain regions, including those for our Wyoming production, have been extremely volatile, and spot sales of natural gas in the region have traded at prices substantially below historic levels, when compared to prices in other primary natural gas sales points in the country. This has been attributed primarily to limitations in available pipeline capacity for natural gas deliveries out of the Rocky Mountain area. Recently, spot prices for Colorado Interstate Gas Rocky Mountains have on occasion dipped to less than $1.00 per MMBtu. This volatility is expected to be significantly alleviated, at least for the near term, by completion of a major pipeline system expected to be online in 2008. Our Wyoming natural gas production is expected to represent less as a percentage of our total U.S. production, as we continue to focus on developing production in East Texas.

Production taxes. We reported production taxes of $256,000 for the three months ended September 30, 2007, down from $345,000 for the comparable period in 2006. The decrease in production taxes was primarily due to severance tax refunds on the Hilltop area wells and to lower taxes in Wyoming due to lower gas prices and revenues.

Lease operating expense. We reported lease operating expenses of $1.7 million for the three months ended September 30, 2007 and 2006. Our lease operating expense per Mcfe was $0.81 per Mcfe during the three months ended September 30, 2007, compared to $1.35 per Mcfe for the comparable period in 2006. The decrease in per Mcfe lease operating expense was primarily the result of higher production volumes and reductions in ad valorem taxes and fixed costs associated with natural gas treatment plants in East Texas.

Transportation and treating. We reported expenses for transportation and treating of $426,000 for the three months ended September 30, 2007, compared to $487,000 for the comparable period in 2006. The decrease was attributable to lower costs per Mcfe in Wyoming.

Depletion, depreciation and amortization. We reported depletion, depreciation and amortization (“DD&A”) of $6.6 million for the three months ended September 30, 2007, up from $3.6 million for the comparable period in 2006. The DD&A rate for the three months ended September 30, 2007 was $3.17 per Mcfe, compared to $2.88 per Mcfe for the three months ended September 30, 2006. Approximately 80% of the increase in DD&A expense was due to higher production volumes, primarily in the Hilltop area.

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General and administrative expenses. We reported general and administrative expenses of $3.2 million for the three months ended September 30, 2007, down from $4.0 million for the comparable period in 2006. The decrease in general and administrative expenses was primarily due to lower stock based compensation, offset by increased personnel costs and Sarbanes-Oxley compliance costs. Non-cash stock-based compensation expense, which is included in general and administrative expenses, was $899,000 for the three months ended September 30, 2007, down from $1.4 million for the comparable period in 2006.

Litigation settlement expense. We reported a litigation settlement expense for the three months ended September 30, 2006 of $465,000, which represented the 2006 settlement cost incurred in conjunction with the Western Gas Resources, et. al., litigation matter. We had no litigation settlement expense for the three months ended September 30, 2007.

Interest expense. We reported interest expense of $4.1 million for the three months ended September 30, 2007, compared to $4.0 million for the comparable period in 2006. For the three months ended September 30, 2007 and 2006, our interest rate was 15.3% (11.1% excluding amortization and accretion charges) and 14.9% (10.9% excluding amortization and accretion charges), respectively.

Investment income and other. We reported $1.1 million in investment income and other for the three months ended September 30, 2007, up from $372,000 for the comparable period in 2006. This increase was due to higher investable cash balances resulting from the sale of undeveloped acreage in the Hilltop area of East Texas in May 2007 and the related sale of common shares.

Nine Months Ended September 30, 2007 Compared to the Nine Months Ended September 30, 2006.

Net loss. We reported a net loss attributable to common shares for the nine months ended September 30, 2007 of $12.1 million, compared to a net loss of $57.3 million for the nine months ended September 30, 2006. Net loss for the nine months ended September 30, 2007 includes a gain of $38.9 million on the sale of a portion of our undeveloped acreage in the Hilltop area of East Texas, which was partially offset by an impairment of natural gas and oil properties of $28.5 million and a litigation settlement expense of $5.0 million related to certain GeoStar matters. The net loss for the nine months ended September 30, 2006 included an impairment of natural gas and oil properties of $37.3 million and a litigation settlement expense of $1.7 million.

Revenues. Substantially all of our revenues are derived from the production of natural gas in the United States. We reported revenues of $25.2 million for the nine months ended September 30, 2007, up from $20.0 million for the comparable period in 2006. The 26% increase in revenues was attributable to a 37% increase in production resulting primarily from the commencement of production of natural gas from new wells in East Texas in 2007. The increase in production was partially offset by a 7% decrease in natural gas prices, primarily related to lower gas prices received for our Wyoming production.

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Natural Gas and Oil Production and Average Sales Prices. Natural gas represents substantially all of our production. The table below sets forth production and sales information for the periods indicated:

Our Wyoming production constituted approximately 28% of our total natural gas production for the nine months ended September 30, 2007 for which we received an average natural gas price of $3.70 per Mcf during the period. Recently, natural gas prices in the Rocky Mountain regions, including those for our Wyoming production, have been extremely volatile, and spot sales of natural gas in the region have traded at prices substantially below historic levels, when compared to prices in other primary natural gas sales points in the country. This has been attributed primarily to limitations in available pipeline capacity for natural gas deliveries out of the Rocky Mountain area. Recently, spot prices for Colorado Interstate Gas Rocky Mountains, have on occasion dipped to less than $1.00 per MMBtu. This volatility is expected to be significantly alleviated, at least for the near term, by completion of a major pipeline system expected to be online in 2008. Our Wyoming natural gas production is expected to represent less as a percentage of our total U.S. production, as we continue to focus on developing production in East Texas.

Production taxes. We reported production taxes of $770,000 for the nine months ended September 30, 2007, down from $1.1 million for the comparable period in 2006. The decrease in production taxes is primarily due to the severance tax refunds on wells in the Hilltop area and to lower taxes in Wyoming due to lower gas prices and revenues.

Lease operating expense. We reported lease operating expenses of $4.9 million for the nine months ended September 30, 2007, up from $4.4 million for the comparable period in 2006. This increase was attributable to higher production volumes and higher workover costs. Our lease operating expense per Mcfe decreased to $1.04 per Mcfe during the nine months ended September 30, 2007 from $1.27 per Mcfe for the comparable period in 2006. The decrease in per Mcfe lease operating expense was primarily the result of higher production volumes, primarily in the Hilltop area.

Transportation and treating. We reported expenses for transportation and treating of $1.1 million for the nine months ended September 30, 2007 and 2006. Transportation and treating costs are primarily related to our Wyoming properties.

Depletion, depreciation and amortization. We reported depletion, depreciation and amortization (“DD&A”) of $16.4 million for the nine months ended September 30, 2007, up from $11.5 million for the comparable period in 2006. The DD&A rate for the nine months ended September 30, 2007 was $3.46 per Mcfe, compared to $3.33 per Mcfe for the nine months ended September 30, 2006. Approximately 87% of the increase in DD&A expense was due to higher production volumes, primarily in the Hilltop area.

Impairment of natural gas and oil properties. For the nine months ended September 30, 2007, we recorded an impairment of $28.5 million, which was reported in the second quarter of 2007 utilizing a weighted average natural gas price of $5.72 per Mcf, held constant. For the nine months ended September 30, 2006, we recorded an impairment of $37.3 million, which was reported in the first quarter of 2006 utilizing a weighted average natural gas price of $5.79 per Mcf, held constant.

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General and administrative expenses. We reported general and administrative expenses of $9.9 million for the nine months ended September 30, 2007, up from $9.6 million for the comparable period in 2006. The increase in general and administrative expenses was primarily due to increased stock based compensation expense. Non-cash stock-based compensation expense, which is included in general and administrative expenses, was $3.1 million for the nine months ended September 30, 2007, up from $2.6 million for the comparable period in 2006.

Litigation settlement expense. We reported a $5.0 million litigation settlement expense accrual for the nine months ended September 30, 2007 related to a proposed settlement with GeoStar on certain matters. The settlement proposal has not been finalized (see Footnote 10, “Commitments and Contingencies – GeoStar Corporation” for additional information). We reported a $1.7 million litigation settlement expense for the nine months ended September 30, 2006, which represented the 2006 settlement cost incurred in conjunction with the Western Gas Resources, et. al., litigation matter.

Interest expense. We reported interest expense of $11.8 million for the nine months ended September 30, 2007, up from $11.6 million for the comparable period in 2006. For the nine months ended September 30, 2007 and 2006, our interest rate was 14.8% (10.7% excluding amortization and accretion charges) and 14.6% (10.6% excluding amortization and accretion charges), respectively.

Investment income and other. We reported $2.2 million in investment income and other for the nine months ended September 30, 2007, up from $1.4 million for the comparable period in 2006. This increase was due to higher investable cash balances resulting from the sale of undeveloped acreage in the Hilltop area of East Texas in May 2007 and the related sale of common shares.

Gain on sales of natural gas and oil properties. In May 2007, we sold a portion of our undeveloped natural gas and oil acreage in the Hilltop area of East Texas for approximately $68.2 million before transaction costs of approximately $1.4 million, resulting in a gain on sale of $38.9 million.

Liquidity and Capital Resources

For the nine months ended September 30, 2007, we reported positive cash flow from operations of $11.2 million. Capital expenditures on natural gas and oil properties totaled $58.7 million during the period. At September 30, 2007, we had approximately $82.0 million in available cash and cash equivalents for future capital expenditures and general corporate purposes.

We continually evaluate our capital needs and compare them to our capital resources. To execute our operational plans, particularly our drilling plans in East Texas and Australia, additional funds will be needed for acreage acquisition, seismic and other geologic analysis, drilling, undertaking completion activities and for general corporate purposes. We may have to significantly reduce our drilling and development program if our internally generated cash flow from operations and cash flow from financing activities are not sufficient to pay debt service, corporate overhead and expenditures associated with our projected drilling and development activities. We expect to fund these expenditures from internally generated cash flow, cash on hand, sale of assets, the issuance of additional debt or equity. We may also attempt to balance future capital expenditures through joint venture development of certain properties with industry partners. We cannot be certain that future funds will be available to fully execute our current business plan. The senior secured notes prohibit us from issuing any debt senior or pari passu to the senior secured notes and may limit our ability to borrow subordinated funds and payment of dividends.

Our capital expenditures in the next 12 months under our current business plan are estimated to total approximately $71.5 million, of which $46.1 million is estimated to be spent on unconventional natural gas and oil exploration and development operations in East Texas, $1.3 million is estimated to be spent on CBM projects in the United States, $6.1 million on additional projects in the U.S. and $18.0 million is estimated to be spent on CBM projects in Australia. Based on our current budget, we have sufficient capital to fund our exploration and development activities in East Texas and Australia for at least the next 12 months.

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Our cash flow and ability to raise capital are highly dependent upon natural gas pricing. A material decrease in current and projected natural gas prices could impact our ability to fund future activities, impair our ability to raise additional capital on acceptable terms and result in a financial covenant default under the senior secured notes, resulting in mandatory principal reduction under certain conditions.

In the third quarter of 2007, the Company entered into a costless collar transaction with a counterparty. The transaction covers notional volume of 2,000 MMBtu per day or 732,000 MMBtu for 2008 with a $5.50 per MMBtu floor and a $7.50 MMBtu ceiling price that represent hedge prices at Inside FERC Colorado Interstate Gas Rocky Mountains (“IFERC CIG Rocky Mountains”). The 2008 volume hedged represents approximately 9% of 2008 projected production from total proved reserves, as estimated by our third party reservoir engineer at June 30, 2007. A senior secured notes covenant restricts us from hedging more than 50% of projected future production.

Off-Balance Sheet Arrangements

As of September 30, 2007, we had no off-balance sheet arrangements. We have no plans to enter into any off-balance sheet arrangements in the foreseeable future.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting US 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:

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 our Annual Report on Form 10-K for the year ended December 31, 2006.

Commodity Risk

Our major commodity price risk exposure is to the prices received for our natural gas production. Realized commodity prices received for our production are the spot prices applicable to natural gas in the region produced. Prices received for natural gas are volatile and unpredictable and are beyond our control. For the three and nine months ended September 30, 2007, a 10% change in the prices received for natural gas production would have had an approximate $970,000 and $2.5 million impact on our revenues, respectively. In September 2007, we entered into a costless collar hedge transaction covering 2,000 MMBtu per day, or 732,000 MMBtu for the year 2008.

Interest Rate Risk

The carrying value of our debt approximates fair value. At September 30, 2007, we had approximately $106.3 million in principal amount of long-term debt of which $73.0 million of senior secured notes was subject to an amended floating interest rate

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equal to the sum of the three-month LIBOR rate at the beginning of the current quarter plus 6.0%. Our convertible senior debentures and subordinated unsecured notes payable are fixed rate debt, but the interest rates are not materially different than current prevailing market rates and, as such, their carrying value approximates fair value. A 10% fluctuation in interest rates would have an approximate $382,000 impact on annual interest expense.

Currency Translation Risk

Our revenues and expenses and the majority of our capital expenditures are primarily in U.S. dollars, thus limiting our exposure to currency translation risk. For the nine months ended September 30, 2007, our Australian activities consisted of capital expenditures totaling approximately $14.0 million. We have no plans in the foreseeable future to implement hedges or financial instruments to manage international currency changes.

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

As required by SEC Rule 13a-15(b), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports that it files under the Exchange Act is accumulated and communicated to the Company’s management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our principal executive officer and principal financial officer have concluded that our current disclosure controls and procedures were effective as of September 30, 2007 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There was no change in our internal control over financial reporting during the quarter ended September 30, 2007 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

A discussion of current legal proceedings is set forth in Note 10 of the Notes to Condensed Consolidated Financial Statements, included herein.