James M. Prince jprince@velaw.com

Tel 713.758.3710 Fax 713.615.5962

September 5, 2007

By Facsimile and Federal Express

Ms. April Sifford

Branch Chief Accountant

Securities and Exchange Commission

Division of Corporation Finance

Mail Stop 7010

Washington, D.C. 20549

Re: Gastar Exploration Ltd.

Form 10-K for the Fiscal year Ended December 31, 2006

Filed March 27, 2007

File No. 1-32714

Dear Ms. Sifford:

On behalf of our client, Gastar Exploration Ltd. (the “Company”), this letter sets forth the responses of the Company to the comments of the staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”) in its comment letter dated August 7, 2007 (the “Comment Letter”) with respect to the Company’s Form 10-K for the fiscal year ended December 31, 2006 and its quarterly report on Form 10-Q for the fiscal quarter ended March 31, 2007.

As set forth in this letter, the Company respectfully requests that the Staff consider permitting the Company, to the extent any of these comments are deemed to require a change in its reporting disclosures, to effect any such changes on a prospective basis in its future reports. The Company does not believe that any suggested changes to its most recently filed Form 10-K and 10-Q’s are sufficiently material to warrant filing amendments to such filings. Please also note that the Company was in the process of finalizing its quarterly report for the quarter ended June 30, 2007 when the Comment Letter was received. That filing may not fully address any changes that may be suggested in the responses to the Comment Letter reflected herein.

For your convenience, we have repeated each comment of the Staff exactly as given in the Comment Letter and set forth below each such comment is the Company’s response. Additionally, where the Company has proposed changes to disclosures based on previous Form 10-K language, we have “hard” marked the proposed changes as deletions and additions.

Vinson & Elkins LLP Attorneys at Law Austin Beijing Dallas Dubai Houston London Moscow New York Shanghai Tokyo Washington First City Tower, 1001 Fannin Street, Suite 2300 Houston, TX 77002-6760 Tel 713.758.2222 Fax 713.758.2346 www.velaw.com

Securities and Exchange Commission  September 5, 2007  Page 2

Form 10-K for fiscal year ended December 31, 2006

Cover Page

COMMENT:

1. We note your non-accelerated filer status and your aggregate value held by non-affiliates at June 30, 2006. Tell us how you determined your filer status under Rule 12b-2 of the Securities Exchange Act of 1934.

RESPONSE:

The Company became subject to the requirements of the Securities Exchange Act of 1934 (the “Act) upon effectiveness of it Registration Statement on Form S-1 (Registration No.333-127498) on January 4, 2006. As a result, the Company did not meet the definitional requirements of “an accelerated filer” under clause (ii) of Rule 12b-2 as of the end of its last fiscal year, December 31, 2006. The Company will have been subject to the reporting requirements of the Act for a period of at least twelve calendar months at the end of its 2007 fiscal year and will first become an accelerated filer with respect to its quarterly report on Form 10-Q for the three months ending March 31, 2008.

Management’s Discussion and Analysis of Financial Condition and Results of

Operations Critical Accounting Policies and Estimates

Asset Retirement Obligation, page 34

COMMENT:

2. We note you attempt to limit the impact of management’s judgment of variables used in your ARO by engaging independent petroleum engineers. While you are not required to make reference to this independent evaluation, when you do, you should also disclose the name of the expert and include the consent of the expert as required by Item 601(a)(23) of Regulation S-K. Please confirm if the engineering consent filed with your Form 10-K is the qualified third party referenced in this disclosure. Please revise to comply with this comment.

RESPONSE:

The independent reserve engineer referred to is Netherland, Sewell & Associates, Inc. (“NSA”), whose consent is included in Exhibit 23.3 in our Annual Report on Form 10-K for the year ended December 31, 2006 (the “2006 Form 10-K”). The Company will revise comparable disclosure in its future filings, to the extent relevant, to reflect the name of the independent reserve engineer as NSA as follows (changes marked from relevant disclosure in 2006 Form 10-K, page 34):

“Effect if different assumptions used. Since there so are many variables in estimating AROs, we attempt to limit the impact of management’s judgment on certain of these variables by using input of qualified third parties. We engage Netherland, Sewell & Associates, Inc., or NSA, independent petroleum engineers, who have consented to the use of their name and reports in this Form 10-K as experts, to evaluate our properties annually. We use the remaining estimated useful life from the year end reserve reports by our independent reserve engineer in

Securities and Exchange Commission  September 5, 2007  Page 3

estimating when abandonment could be expected for each property. We expect to see our calculations impacted significantly if interest rates move from their current lows, as the credit-adjusted-risk-free rate is one of the variables used on a quarterly basis. Our technical team developed a standard cost estimate based on historical costs, industry quotes and depth of wells. Unless we expect a well’s plugging to be significantly different than a normal abandonment, we use this estimate. The resulting estimate, after application of a discount factor and some significant calculations, could differ from actual results, despite all our efforts to make an accurate estimate.”

Balance Sheet, page F-4

COMMENT:

3. Tell us and disclose your distinction between revenues receivables and accounts receivables, net.

RESPONSE:

Revenue receivables represent exclusively receivables from third party purchasers of the Company’s oil and gas production. Accounts receivable represents primarily joint interest billing receivables from third party non-operated interest owners in Company operated properties and other miscellaneous receivables. The Company expanded the accounts receivable disclosure in an attempt to furnish the reader of the Company’s financial statements greater clarity as to the nature of its receivables. The Company will clarify this distinction in future filings.

Note 3. Cash Call Receivable, page F-13

COMMENT:

4. We note this balance represents the proportionate share of planned authorized expenditures payable to the operator and an advance payment to a drilling contractor. It is not clear why the amounts payable to the operator represent a receivable. Please revise your disclosure to clarify what this balance represents, how you account for these payments and why it should be considered a long-term receivable. Further, tell us and disclose why your amortization period is appropriate and how the amortization reduces your capitalized natural gas and oil property costs.

RESPONSE:

Upon receipt of the Staff’s comment the account title has been changed from Cash Call Receivable to Drilling Advances in the Company’s quarterly report on Form 10-Q for the fiscal quarter ended June 30, 2007. The balance in the account is comprised of two types of advance payments – (1) drilling advances paid to third party operators and (2) an advance payment to a drilling contractor to secure a drilling rig. The drilling advances paid to operators represent the Company’s pre-payment of future drilling operation costs pursuant to approved authorization of expenditures (“AFE”). As AFE expenditures are incurred by the

Securities and Exchange Commission  September 5, 2007  Page 4

operator, they are billed to the Company and the advance payment reduced with typically a corresponding increase in natural gas and oil properties. As required by contract, the advance payment to a drilling contractor is being amortized over a three-year period commencing November 2006. As the drilling advance payment is reduced, there is a corresponding increase in natural gas and oil properties. These advance payments are included in long-term Other Assets versus current assets because, upon incurring the related expenditures, the reduction in these advance payments will not result in reduction in current assets but will ultimately result in reclassification to long term natural gas and oil properties. The Company will revise comparable disclosure in our future filings, to the extent relevant, as follows (changes marked from disclosure in 2006 Form 10-K, page F-13):

“3. Cash Call Receivable Drilling Advances

Drilling advances represent Cash call receivable represents the Company’s proportionate share of planned authorized drilling expenditures payable paid to the operator upon execution of the final drilling authorization of expenditures and an advance payment to a drilling contractor. Of the total cash calls drilling advances paid during the year ended December 31, 2006, $8.2 million was paid to Geostar Corporation (“Geostar”), a significant shareholder at the time, and the remainder was paid to other outside parties. In 2005, Geostar refunded $2.1 million of unused cash call balances drilling advances to the Company pursuant to the acquisition of Geostar’s working interests in East Texas. The Company made advance payments totaling $2.0 million to a drilling contractor prior to the delivery of a drilling rig in November 2006. The Pursuant to the contract, the advance payments will be amortized over the three-year term of the drilling contract agreement on a straight line basis as a reduction an increase to capitalized natural gas and oil property costs.”

The Company will make changes, to the extent relevant, to the notes to condensed consolidated financial statements in our future Form 10-Q filings.

Note 6. Long-term Debt

Senior Secured Notes, page F-17

COMMENT:

5. We note in connection with the senior secured note issuances, you agreed to issue additional common shares at closing, and on each of the six, twelve and eighteen-month anniversaries of the closing date, for no additional consideration. We also note you recorded a liability of $17.0 million and a corresponding amount recorded as a debt discount. Citing the appropriate accounting literature, tell us and disclose how you accounted for this transaction, and how you will account for subsequent issuances on each closing anniversary.

RESPONSE:

Reference is made to the Company’s response to the prior comments of the Staff of the SEC in correspondence dated November 22, 2005, Item 22.

Securities and Exchange Commission  September 5, 2007  Page 5

Statement of Financial Accounting Standard No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (“FAS 150”) paragraph 12 states:

“A financial instrument that embodies an unconditional obligation, or a financial instrument other than an outstanding share that embodies a conditional obligation, that the issuer must or may settle by issuing a variable number of its equity shares shall be classified as a liability (or an asset in some circumstances) if, at inception, the monetary value of the obligation is based solely or predominantly on any one of the following:

a. A fixed monetary amount known at inception (for example, a payable settleable with a variable number of the issuer’s equity shares)

b. Variations in something other than the fair value of the issuer’s equity shares (for example, a financial instrument indexed to the S&P 500 and settleable with a variable number of the issuer’s equity shares)

c. Variations inversely related to changes in the fair value of the issuer’s equity shares (for example, a written put option that could be net share settled).”

Based on FAS 150 paragraph 12 (a), the future issuance of shares is a fixed monetary amount known at inception which occurred upon the issuance of the senior secured notes. The liability for common shares future issuance of CDN $4.5 million and CDN $714,286 upon issuance and the next three anniversary dates had been reflected as a long term liability separate of senior secured notes in our original filing statement under the caption of liabilities to be settled via the issue of common shares. As the common shares are issued the common issuance share liability will be reduced with a corresponding increase in common stock.

The common stock liability to be settled in the future was based on the contractual valuation specified and recorded as a debt discount to the senior secured note liability. The resulting senior secured note debt discount is being amortized using the effective interest rate method over the term of the notes. The last issuance of common shares took place on March 19, 2007.

COMMENT:

6. We also note you have the right on a quarterly basis to require the note holders to purchase up to an aggregate of $10.0 million of additional senior notes through June 16, 2007. Tell us and disclose the specific terms of this arrangement, including if there is a pre-determined interest rate for these notes. In your response, please address how you have accounted for this right in your financial statements.

RESPONSE:

The Company had until June 16, 2007 to require the note holders to purchase up to an aggregate of $10.0 million principal amount of additional senior secured notes, which it did not exercise. The Company did not issue the additional $10.0 million of senior secured notes. If the notes were issued, they were to bear the same terms and interest rate as the previously issued senior notes. The issuance of additional senior secured notes was contingent upon meeting various conditions, including a requirement that a reserves PV(10) valuation to

Securities and Exchange Commission  September 5, 2007  Page 6

senior secured notes debt coverage ratio was at a minimum of 2:1. The Company would also have been required to issue to note holders subscription receipts entitling them to receive, for no additional consideration, additional common shares on similar terms as those issued with the original senior secured notes in a pro rata amount based on the additional principal amount of the senior secured notes.

Since the issuance of future senior secured notes was at the Company’s future election, subject to covenant compliance, and the Company never expressed an intention to exercise this right, no financial statement or accounting impact was included in the Company’s financial statement for this future contingent right beyond footnote disclosure. Although not controlling, we note that the Commission staff did not raise this accounting treatment as an issue in its review of the Company’s initial registration statement on Form S-1.

Note 13. Related Party Transactions

Geostar Corporation, page F-26

COMMENT:

7. We note the look-back calculations are based on a third party engineering report. While you are not required to make reference to this third party engineering report, when you do you should also disclose the name of the expert and include the consents of the expert. Please revise to comply with this comment.

RESPONSE:

We do not believe the description of a contractual term that requires a third party report, or the conclusion that the third party report met certain conditions, makes that third party an “expert” as contemplated in the Securities Act of 1933, as amended, or Rule 436 of the Commission. No part of any report of the third party is being reported or being summarized for its content, the Company is simply stating that the terms of the contract require a third party report and disclosing the fact that a condition for the issuance of new shares was not met.

Form 10-Q for period ended March 31, 2007

Note 4. Long-Term Debt

Senior Secured Notes, page 7

COMMENT:

8. We note you were not in compliance with one of your debt covenants at March 31, 2007, and received a waiver of the covenant default on May 9, 2007. Please tell us and disclose the nature of the default in more detail. Further, tell us and disclose the period of the waiver and your consideration of EITF 86-30 and SFAS No. 78 in classifying the notes as long-term liabilities on your balance sheet.

Securities and Exchange Commission  September 5, 2007  Page 7

RESPONSE:

The senior secured financial covenant ratio tests are based on “net debt”, defined as senior secured debt maturity value less cash at the period end, as compared to the present value (“PV(10)”) of proved (“1P”) reserves and proved and probable (“2P”) reserves. As disclosed in the Company’s Form 10-Q for the first quarter of 2007, based on financial statements and reserve data at March 31, 2007, the Company was in compliance with the 1P PV(10) ratio of 1.5:1 but would not have been in compliance with the 2P PV(10) ratio of 3.0:1. To maintain ratio compliance would have required a senior secured principal payment of $13.2 million or would have required a waiver. Prior to reporting results of operations for the first quarter of 2007, the Company sold a portion of its East Texas undeveloped leasehold and 10 million newly issued common shares for $88.2 million. The post quarter end sale of leasehold acreage and shares increased the Company’s cash position resulting in compliance with all debt covenant ratios. As a result of the leasehold acreage and common shares sale, the Company received a waiver of the covenant default without any principal payment being required. Pursuant to EITF 86-30, the Company cured the potential covenant default prior to issuance of the financial statements and made the determination that it was probable that the Company would continue to be in compliance with the covenant test at subsequent test dates, and thus the senior secured debt was reflected as long-term debt.

Engineering comments:

General

COMMENT:

9. Please provide us with a copy of your reserve report as of December 31, 2006. If possible, please submit in electronic format such as CD-ROM. For reserves classified as proved producing, provide a graph of the production over time with the forecasted production decline also on the graph.

RESPONSE:

The requested information is being furnished supplementally under separate cover to Mr. Murphy of the Staff. The Company has requested FOIA confidential treatment under Rule 83 for such supplemental materials. Pursuant to the letter to Mr. James Murphy containing the FOIA confidential treatment request dated September 5, 2007, the Company also requests the return of the supplemental information upon completion of its review in accordance with Rule 418(b).

Business, page 1

Our strategy, page 1

COMMENT:

10. You indicate that your CBM reserves are long-lived. We note that your total reserve life is less than 7 years even though almost two-thirds of your reserves are not producing or undeveloped. As the Powder River Basin coal-bed methane wells have a life of about 7-8 years, please revise to further explain this point or remove this disclosure.

Securities and Exchange Commission  September 5, 2007  Page 8

RESPONSE:

The Company respectfully requests that the Staff consider permitting the Company to affect changes, to the extent relevant, on a prospective basis in its future filings by removing the reference to “long-lived” when referring to its CBM projects and reserves.

Natural Gas and Oil Activities, page 2

COMMENT:

11. Please expand your disclosure to include all the information required by Item 102 of Regulation S-K for you principal fields. This includes production, reserves, nature of your interest, development, and location of your principal fields. Include any future planned activity regarding further development in these fields.

RESPONSE:

Please note that on page 38 under Liquidity and Capital Resources of the 2006 Form 10-K, the Company discusses its future capital expenditures by area.

The Company will make the following disclosure changes, to the extent relevant, on a prospective basis in its future reports as follows (changes marked from disclosure in the 2006 Form 10-K, page 2):

“Hilltop Area, East Texas

For the year ended December 31, 2006, our net production from the Hilltop area averaged approximately 7.9 MMcfed. As of December 31, 2006, Hilltop area total proved developed and proved undeveloped reserves were 14,705 MMcfe and 6,299 MMcfe, respectively, representing approximately 67% of the Company’s total proved reserves.”

“Coalbed Methane – Powder River Basin, Wyoming

For the year ended December 31, 2006, our average net production from our CBM properties in the Powder River Basin was approximately 4.8 MMcfed. As of December 31, 2006, Powder River Basin total proved developed and proved undeveloped reserves were 5,492 MMcfe and 10,253 MMcfe, respectively, representing approximately 33% of the Company’s total proved reserves.”

Markets and Customers, page 4

COMMENT:

12. You indicate that you and your partners are “finalizing plans for a gathering system and pipeline” for your PEl238 [sic] concession. Please revise to expand this disclosure to fully explain what you mean by “finalizing plans” by including the status of approval, estimated costs and the approximate timing and duration of construction of the project.

Securities and Exchange Commission  September 5, 2007  Page 9

RESPONSE:

The Company respectfully requests that the Staff consider permitting the Company to affect the following disclosure change, to the extent relevant, on a prospective basis in future filings to read as follows (changes marked from disclosure in the 2006 Form 10-K, page 4):

“Australian natural gas markets and infrastructure exist and are viable markets; however, they are not as developed as the markets and infrastructure in the United States. Specifically, the PEL 238 concession is currently not served by natural gas infrastructure. The initial gas market for PEL 238 natural gas is anticipated to be an electricity generation facility owned and operated by our joint venture partner and located near the town of Narrabri, New South Wales, Australia. Although there currently is no pipeline from the existing and planned CBM project areas, we and our joint venture partner are planning to complete a gathering system and pipeline by March 2008 to transport our CBM gas to the electricity generation facility. The gathering system and pipeline have been designated as “Major Projects” under Part 3A of the Environmental Planning and Assessment Act 1979 by the New South Wales Minister for Planning and thus we believe that the necessary permits and approvals will be obtained on a timely basis. Our joint venture partner, and the operator of the project, expects to obtain all required rights of way, approvals and permits necessary for the completion of the pipeline by early 2008. The gathering system and pipeline gross cost are estimated to be approximately $10.5 million.”

Risk Factors, page 12

COMMENT:

13. Include risk factors that disclose the drilling and operating risks and costs associated with handling gas containing high levels of hydrogen sulfide and carbon dioxide and other contaminants such as in the Bossier trend of East Texas. Include how this affects your results and may affect them in the future and the fact that if your gas processing plant is out of commission or exceeding capacity you may have to shut-in production due to not meeting minimum pipeline specifications for your natural gas.

RESPONSE:

Like most other oil and gas production, the Company’s ability to operate and market our natural gas in the Hilltop area of our deep Bossier play in East Texas is impacted by the additional costs and risks associated with removing excess contaminants above pipeline delivery specifications. In the Hilltop area, that includes excess levels of hydrogen sulfide, carbon dioxide and other contaminants. We currently incur additional fees to treat the natural gas produced from the Hilltop area to meet pipeline delivery specifications and any disruption in treating services could limit our ability to sell natural gas.

Securities and Exchange Commission  September 5, 2007  Page 10

The Company respectfully requests that the Staff consider permitting the Company to revise the following risk factor, to the extent still relevant, on a prospective basis in future filings to read as follows (changes marked from disclosure in the 2006 Form 10-K, page 19):

“Approximately 66% two-thirds of our revenues for the year ended December 31, 2006 was from the production of wells located in our deep Bossier play in East Texas, where production must be treated for removing excess carbon dioxide and hydrogen sulfide in excess of pipeline delivery specifications. Any disruption in production or our ability to process and sell our natural gas production from this area would have a material adverse effect on our results of operations.

Production of the natural gas in the deep Bossier play in East Texas could unexpectedly be disrupted or curtailed due to reservoir or mechanical problems. Our natural gas produced from this area contains levels of carbon dioxide and hydrogen sulfide that are above levels accepted by gas purchasers. We must treat this production prior to marketing or pay fees to the purchaser to treat the production. Currently Additionally, a majority of our East Texas production is processed through two on-site processing facilities. If these facilities ceased to operate, were destroyed or otherwise needed replacement, it could require 60 to 90 days to replace either one or both of these facilities. A 60 to 90 day curtailment of our East Texas production could reduce current revenues by an estimated $3.1 to $4.6 million, with a corresponding reduction in our cash flow.”

COMMENT:

14. As you operate in areas that are subject to possible prior drainage of reserves, such as the Powder River Basin, this should be included as a risk factor. Please revise your document to include this and how it may have impacted your results in the past and may impact you in the future.

RESPONSE:

The Company respectfully requests that the Staff consider permitting the Company to add the following additional risk factor, to the extent still relevant, on a prospective basis in its future filings to read as follows:

“The coal beds from which we produce may be drained by offsetting production wells.

Our drilling locations are spaced primarily using 80-acre spacing. Producing wells located on the 80-acre spacing units contiguous with our drilling locations may drain the acreage underlying our wells. If a substantial number of productive wells are drilled on spacing units adjacent to our properties, it could have an adverse impact on the economically recoverable reserves of our properties that are susceptible to such drainage.”

Securities and Exchange Commission  September 5, 2007  Page 11

COMMENT:

15. Please revise your document to include a risk factor that the typical coal-bed methane well in the Powder River Basin produces at a significantly lower gas rate and will recover significantly less reserves than a conventional gas well. Explain how this has impacted your results in the past and may impact your future results.

RESPONSE:

The Company respectfully requests that the Staff consider permitting the Company to add the following additional risk factor on a prospective basis, to the extent still relevant, in its future reports as follows:

“Our coal bed methane wells typically have a shorter reserve life and lower rates of production than conventional natural gas wells, which may adversely affect our profitability during periods of low natural gas prices.

The shallow coals from which we produce natural gas in the Powder River Basin typically have a seven to eight year reserve life and have lower total reserves and produce at lower rates than most conventional natural gas wells. We depend on drilling a large number of wells each year to replace production and reserves in the Powder River Basin and to distribute operational expenses over a larger number of wells. A decline in natural gas prices could make certain wells uneconomical because production rates are lower on an individual well basis and may be insufficient to cover operational costs.”

Our success is influenced by natural gas prices in the specific areas where we operate, page 13.

COMMENT:

16. You indicate this had a negative impact on your results in 2002. Please revise to expand your discussion to include more recent periods.

RESPONSE:

The Company respectfully requests that the Staff consider permitting the Company to revise the following risk factor, to the extent relevant, on a prospective basis in its future filings to read as follows (changes marked from disclosure in the 2006 Form 10-K, page 13):

“Our success is influenced by natural gas prices in the specific areas where we operate, and these prices may be lower than prices at major markets.

Even though overall natural gas prices at major markets, such as Henry Hub in Louisiana may be high, regional natural gas prices may move somewhat independent of broad industry price trends. Because some of our operations are located outside major markets, we are directly impacted by regional natural gas prices regardless of Henry Hub or other major market pricing. For example, surplus natural gas supplies relative to available transportation in the Powder River Basin in

Securities and Exchange Commission  September 5, 2007  Page 12

2002 caused local natural gas prices to be much less than national natural gas prices, and we, therefore, were unable to take advantage of those higher national natural gas prices. Approximately 67% of the Company’s production is priced based on the Katy Hub basis point and the remainder is priced on Colorado Interstate Gathering (CIG). Recently average Katy and CIG hub basis has been trading at approximately 6% and 25%, respectively, less then Henry Hub. The CIG hub basis has been most erratic and has traded at even higher discounts to Henry Hub for certain periods of time. Low natural gas prices in any or all of the areas where we operate would negatively impact our financial condition and results of operations.”

The imprecise nature of estimating proved natural gas and oil reserves, future downward revisions of proved reserves and increased drilling expenditures….may lead to write-downs in the carrying value of our natural gas and oil properties, page 16

COMMENT:

17. Please revise to make this risk factor more specific to you. In the recent past you have experienced impairments of certain properties, therefore, please disclose these and how they have impacted your results for those periods.

RESPONSE:

The Company respectfully requests that the Staff consider permitting the Company to revise the following risk factor, to the extent relevant, on a prospective basis in its future filings to read as follows (changes marked from disclosure in the 2006 Form 10-K, page 16):

“The imprecise nature of estimating proved natural gas and oil reserves, future downward revisions of proved reserves and increased drilling expenditures without current additions to proved reserves may lead to write downs in the carrying value of our natural gas and oil properties.

Due to the imprecise nature of estimating natural gas and oil reserves as well as the potential volatility in natural gas and oil prices and their effect on the carrying value of our natural gas and oil properties, we have incurred write downs in the future past and may be required as a result of factors that may negatively affect the present value of proved natural gas and oil reserves continue to incur write downs in the future. These factors can include volatile natural gas and oil prices, downward revisions in estimated proved natural gas and oil reserve quantities, limited classification of proved reserves associated with successful wells and unsuccessful drilling activities. In 2006 and 2005, we incurred impairment of natural gas and oil properties of $56.3 and $8.7 million, respectively. These non-cash impairments were primarily the result of declines in natural gas prices at the date of measurement and did not impact our net cash provided by operating results. Our weighted average natural gas price at the impairment determination date used for impairment evaluation at December 31, 2006 was $6.11 compared to a December 31, 2005 weighted average price of $7.39 per Mcf. The 2005 impairment of natural gas and oil properties was the result of natural gas prices declining to $5.32 per Mcf at June 30, 2005.”

Securities and Exchange Commission  September 5, 2007  Page 13

We cannot control the activities on properties we do not operate………page 21

COMMENT:

18. You indicate that others operate “some” of the properties you have an interest in. Please revise to clearly specify the percentage of your properties and reserves that are operated by others.

RESPONSE:

The Company respectfully requests that the Staff consider permitting the Company to revise the following risk factor, to the extent relevant, on a prospective basis in its future filings to read as follows (changes marked from disclosure in the 2006 Form 10-K, page 21):

“We cannot control the activities on properties we do not operate, which may affect the timing and success of our future operations.

Other companies operate some of the properties in which we have an interest. As a result operated approximately 39% of our 2006 annual production and approximately 33% of our proved reserves at December 31, 2006. We have a limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could have a material adverse affect on the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors that are outside of our control, including:

• Timing and amount of capital expenditures;

• The operator’s expertise and financial resources;

• Approval of other participants in drilling wells; and

• Selection of technology.”

Properties, page 24

Production, Prices and Operating Expenses, page 25

COMMENT:

19. Please tell us if these are the average oil and gas prices before hedging that you received in 2005 and 2006.

RESPONSE:

The average natural gas and oil prices disclosed were before hedging as the Company did not have any commodity price hedges in place during 2005 and 2006. As disclosed under Item 7A. Commodity Price Risk, to date the Company has not entered into hedge transactions to mitigate our commodity price risk. To date in 2007, the Company has not entered into any commodity hedges.

Securities and Exchange Commission  September 5, 2007  Page 14

Drilling Activity, page 25

COMMENT:

20. Please revise to fully explain the category of “undecided” under exploratory well results for 2005 and 2006 or provide a cross-reference if it is explained elsewhere in the document.

RESPONSE:

The Company respectfully requests that the Staff consider permitting the Company to make the following disclosure change, to the extent relevant, on a prospective basis in its future filings to read as follows (changes marked from disclosure in the 2006 Form 10-K, page 25):

“The following table shows our drilling activity for the periods indicated. In the table, “gross” wells refer to wells in which we have a working interest, and “net” wells refer to gross wells multiplied by our working interest in such wells. Exploratory “undecided” wells are CBM wells are wells for which permanent equipment was installed for the production of natural gas or oil but that as of each respective period end were in the process of de-watering drilled in Australia that have been successfully completed but are in the process of de-watering to determine if commercial natural gas production can be obtained.”

Notes to Consolidated Financial Statements

Supplemental Oil and Gas Disclosures – Unaudited, page F-37

Net Proved and Proved Developed Reserve Summary, page F-39

COMMENT:

21. In your registration statement you disclosed that a Reserves Committee of the Board of Directors and senior management reviewed the reserves and approved the annual reserve report. However, we could find no such disclosure in your 2005 or your current 10-K. You indicated in a response to us on October 13, 2005, that you believed they provide a meaningful review and control function. Please provide us with the current status of that committee and their work and explain to us why this is not disclosed in the annual 10-K reports.

RESPONSE:

The Company did not provide disclosure about its Reserve Committee and its responsibilities in its 2005 and 2006 Form 10-K, as such information was included in its 2006 and 2007 Proxy Statement. The Company plans to continue such disclosure in future Proxy Statements, however, the Company respectfully requests that the Staff consider permitting the Company to make the following disclosure as additional paragraphs, to the extent relevant, on a prospective basis in its future filings to read as follows (changes marked from disclosure in the 2006 Form 10-K, page F-37):

Securities and Exchange Commission  September 5, 2007  Page 15

“22. Supplemental Oil and Gas Disclosures – Unaudited

The following disclosures for the Company are made in accordance with SFAS No. 69, “Disclosures About Oil and Gas Producing Activities”.

Estimates of proved developed and proved undeveloped reserves as of December 31, 2006, 2005 and 2004, were based on estimates prepared by Netherland, Sewell & Associates Inc. (“NSA”) an independent petroleum reservoir engineer.

Our independent engineer is engaged by and provides their reports to the Reserve Committee of the Board of Directors. The reservoir engineer is independent and engaged to prepare the reserves reports rather than to audit reports prepared by the Company. Company management provides representation to the independent engineers that we have provided all relevant operating data and documents, and management reviews the reports to ensure completeness and accuracy. The Reserve Committee of the Board of Directors, Abby Badwi, Thomas Crow, and Richard Kapuscinski, independent directors of the Company, are charged with review of the reserve report of independent engineers on Company reserves. Members of the Reserve Committee have experience in the natural gas and oil gas exploration and production industry, but none of the members of the Reserves Committee are licensed petroleum engineers. The Reserve Committee meets with representatives of its independent petroleum engineers to review the year end engineering reports.

COMMENT:

22. Although you have provided explanations for the revisions of reserves presented for these three periods, please expand your disclosure to provide the appropriate explanations for the other significant changes in reserves presented under Purchase of minerals in place and extensions and discoveries. See paragraph 11 of SFAS 69.

RESPONSE:

The Company respectfully requests that the Staff consider permitting the Company to make the following disclosure change, to the extent relevant, on a prospective basis in its future filings to read as follows (changes marked from disclosure in the 2006 Form 10-K, page F-40):

“The 2005 purchase of minerals in place represent East Texas and Wyoming proved reserves acquired pursuant to the Geostar Acquisition. The 2006 downward revision of previous estimates is primarily attributed to a decrease in natural gas prices and performance revisions in our Powder River Basin reserves in Wyoming. A decline in natural gas prices of approximately 36% from 2005 resulted in a decrease in proved reserves of approximately 4,836 MMcf. The remaining proved reserve revision of previous estimates is attributed to downward revisions in the Powder River Basin based on updated well performance and reservoir pressure data, which was partially offset by upward performance revisions in the East Texas Bossier field.

Securities and Exchange Commission  September 5, 2007  Page 16

In connection with these responses, the Company acknowledges that:

• the Company is responsible for the adequacy and accuracy of the disclosure in the filing;

• staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

• the Company may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.”

        If you have any questions or wish to discuss, please do not hesitate to contact the undersigned at 713-758-3710, or Michael Gerlich, Chief Financial Officer of the Company, at 713-739-1800.

Very truly yours,

/s/ James M. Prince

James M. Prince

cc: J. Russell Porter (Gastar)

Michael Gerlich (Gastar)

T. Mark Kelly (Firm)

Theodore Moore (Firm)