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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act. Yes  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  ¨    No  x

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

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 Securities Exchange Act of 1934). Yes  ¨    No  x

The aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the closing price of $2.39 per common share on the American Stock Exchange at the close of business on June 30, 2006 (the last business day of the registrant’s most recently completed second fiscal quarter) was $264,195,433.

As of March 20, 2007, there were 195,341,375 common shares outstanding.

Documents incorporated by reference. None

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2006

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Cautionary Statement about Forward-Looking Statements

Some of the information included in this Form 10-K contains “forward-looking statements”. These statements can be identified by the use of forward-looking words, including “may”, “expect”, “anticipate”, “plan”, “project”, “believe”, “estimate”, “intend”, “will”, “should” or other similar words. Forward-looking statements may include statements that relate to, among other things:

Although we believe the expectations reflected in such forward-looking statements are reasonable, we cannot assure you that such expectations will occur. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from actual future results expressed or implied by the forward-looking statements. These factors include among others:

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You should not unduly rely on these forward-looking statements in this Form 10-K, as they speak only as of the date of this Form 10-K. Except as required by law, we undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this Form 10-K or to reflect the occurrence of unanticipated events. See the information under the heading “Item 1A. Risk Factors” for some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in forward-looking statements.

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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) “convertible debentures” refers to our $30.0 million principal amount of 9.75% convertible senior unsecured debentures, (iv) “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 debentures and certain other subordinated notes as partial compensation for their services, (v) “senior secured notes” refers to our $73.0 million principal amount of senior secured notes issued in 2005, (vi) all dollar amounts appearing in this Form 10-K are stated in U.S. dollars unless specifically noted in Canadian dollars (“CDN$”), and (vii) all financial data included in this Form 10-K has been prepared in accordance with generally accepted accounting principles in the United States of America.

PART I

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 additional unconventional natural gas exploration in the deep Bossier play in the Hilltop area in East Texas. Our primary CBM properties are in the Powder River Basin in Wyoming and in the Gunnedah and Gippsland Basins of Australia. Gastar Exploration Ltd. is a Canadian corporation that is subsisting under the Business Corporations Act (Alberta).

Our Strategy

Management believes that:

Based on these beliefs, we have pursued a strategy that includes:

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Natural Gas and Oil Activities

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

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. This area is an emerging unconventional play and has attracted some of the largest and most active operators in the U.S. Wells in this area target multiple potentially productive natural gas geologic horizons and are typically characterized by high initial production, significant decline rates and long-lived reserves. We have accumulated 51,975 gross (26,374 net) acres in the Bossier play. Our first successful well was spudded in 2003 and placed on production in September 2004. During 2004 and 2005, we drilled an additional 6 gross (5.5 net) wells in the Hilltop area. During 2006, we continued our exploratory drilling program in the Hilltop area by drilling an additional 4 gross (2.3 net) wells. In May 2006, we increased the number of drilling rigs in the Hilltop area to two rigs, and in November 2006, we added a third drilling rig under a three year contract to expedite our Bossier drilling activity. As of December 31, 2006, we had successfully completed 10 of 11 deep Bossier wells. For the year ended December 31, 2006, our net production from the Hilltop area averaged approximately 7.9 MMcfed.

We are participating in a 3-D seismic survey that will cover the majority of our acreage position in the Hilltop area. The 3-D seismic data should be available for processing early in the second quarter of 2007 and available for interpretation later that quarter. We currently have plans to drill an additional eight deep Bossier wells during 2007.

Coalbed Methane—Powder River Basin, Wyoming

We own an approximate 40% average working interest in 54,966 gross (21,854 net) acres in the Powder River Basin of Wyoming. The Powder River Basin has been an important natural gas and oil producing area for nearly 100 years. Generally, CBM wells are shallow and less costly than conventional natural gas wells. Our primary areas of activity in the Powder River Basin are Squaw Creek, Ring of Fire and adjacent fields, all of which are located north of Gillette, Wyoming in an active drilling area.

During 2006, we participated in the drilling of approximately 43 (19.5 net) wells. Based on our third party reservoir engineering report at December 31, 2006, we had an interest in 258 gross (104.7 net) economic CBM wells producing in the Basin. 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. We anticipate continuing an active recompletion and drilling program in 2007.

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

We have a 35% interest in PEL 238, a CBM exploratory property covering approximately 2.0 million gross (700,000 net) acres, located in the Gunnedah Basin of New South Wales, approximately 250 miles northwest of Sydney, Australia, near the town of Narrabri. We believe that the strategic location of these potential CBM reserves near the large natural gas markets in Sydney-Newcastle-Wollongong area, and the concession’s location relative to other developing gas markets should create a competitive advantage for the natural gas reserves that may be developed on PEL 238.

Extensive coring of the coal on PEL 238 by the Australian government has provided a thorough understanding of the coal resources and potential CBM resource in place on our license. Two primary coal seams are found on the PEL 238 license, the Late Permian aged Hoskisson coal formation and the Early Permian aged Maules Creek coal formation.

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During 2006, we participated with our joint venture partners in the drilling of eight new vertical coal seam natural gas wells on approximately 40-acre spacing in close proximity to an existing well within the Bohena Project Area. The new wells have been successfully completed, and the pilot program wells were placed into test production in late 2006. The closely spaced “nine-spot” production pilot is designed to accelerate dewatering of the Bohena coal seam and to achieve commercial natural gas production rates in a shorter time period than would be possible for an isolated well or for wells drilled on wider spacing. The early 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. Our current pilot program will evaluate the commercialization of the Gunnedah Basin CBM project, with a target to achieve initial certified natural gas reserves by the end of 2007.

In March 2007, we announced that we and our joint venture partner had executed a Memorandum of Understanding with Macquarie Generation, a NSW 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 potential long-term natural gas supply and purchase agreement could reach as much as 500 billion cubic feet in total and increase NSW’s natural gas consumption by as much as 25%.

The area on which PEL 238 is located is subject to native title claims; however, no such claims have been lodged at this time.

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

We have a 75% interest in the CBM rights in EL 4416, an approximate 1.0 million gross (750,000 net) acre property covering a substantial part of the onshore portion of the Gippsland Basin of Victoria, Australia, located approximately 130 miles east of Melbourne. The EL 4416 property is well situated with three existing natural gas transmission lines running through the license area from productive offshore fields to a large natural gas processing facility and then to markets near Sydney, Melbourne and in Tasmania. The EL 4416 coal is classified as low-rank brown coal. The Victorian government has extensively evaluated the potential coal resources through detailed coal resource studies. Due to our large acreage position and the fact that this thick coal is present over a large percentage of the license area, the CBM resource potential is believed to be significant.

During 2006, we began initial long-term testing of the first of two wells completed on EL 4416. Before a pump failure, early water production had been significant, indicating permeability in the targeted coal seam. We have pre-funded $6.5 million for a 10-well drilling program, which commenced late fourth quarter 2006. The program includes the establishment of two “5-spot” pilots, one incorporating two existing wells and 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 16 “Commitments and Contingencies - Litigation” to our consolidated financial statements beginning on page F-1 of this report.

The area on which EL 4416 is located is subject to native title claims. Three native title claims have been lodged over the area which includes EL 4416 in Victoria. The Gunai/Kurnai People claim is registered and two others, the Gunai/Kurnai/Boonerwring claim and Kurnai People claim, are applications. The Kurnai People claim overlaps with the Gunai/Kurnai People’s claim and have been in dispute for four to five years. The claims remain

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in intra-indigenous mediation with the National Native Title Tribunal. The existence of these competing claims may prolong any mandatory negotiation process undertaken in relation to this area.

Markets and Customers

The success of our operations is dependent upon prevailing prices for natural gas and oil. The markets for natural gas and oil have historically been volatile and may continue to be volatile in the future. Natural gas and oil prices are beyond our control. However, rising demand for natural gas to fuel power generation and meet increasing environmental requirements has led some industry observers to indicate that long-term demand for natural gas is increasing.

Our current United States production has access to major intrastate and interstate pipeline systems. We contract to sell natural gas from our properties with spot market contracts that vary with market forces on a monthly basis. While overall natural gas prices at major markets, such as Henry Hub in Louisiana, may have some impact on regional prices, the regional natural gas price at our production facilities may move somewhat independently of broad industry price trends. Because some of our operations are located in specific regions, we are directly impacted by regional natural gas prices in those regions regardless of pricing at major market hubs. The East Texas Basin area has an extensive natural gas pipeline infrastructure in place. Our deep Bossier production is transported to the Katy Hub in Katy, Texas, where numerous parties are available to purchase our natural gas production. Powder River Basin natural gas is sold under spot market contracts to major pipeline and natural gas marketing companies. These companies purchase essentially all of our current production.

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 finalizing plans for a gathering system and pipeline to transport our CBM gas to the electricity generation facility.

The longer term market for PEL 238 natural gas is considered to be future gas-fired power generation facilities in New South Wales and the industrial and residential markets in the Sydney-Newcastle-Wollongong areas of New South Wales. In March 2007, we announced that we had executed, along with our PEL 238 joint venture partner, a Memorandum of Understanding (“MOU”) with Macquarie Generation, a government-owned electricity generator in the state of New South Wales, Australia. The MOU sets the framework for negotiation of a potential long-term agreement to supply natural gas for the expansion of Macquarie Generation’s Bayswater power station.

The EL 4416 license in the Gippsland Basin of Victoria, the site of recent pilot CBM drilling and planned production testing, is served by three existing natural gas transmission pipelines. The existing pipelines have capacity to transport natural gas from the EL 4416 license to markets in the area of Sydney, Melbourne and Tasmania. If our efforts result in commercial CBM production from this license, minimal infrastructure expenditures would be necessary to connect to existing pipelines. Victoria has both a spot market for natural gas and a developed market for contract sales of natural gas.

Our very limited oil production in Texas and West Virginia is sold under spot sales transactions at market prices. The availability and price responsiveness of the multiple oil purchasers provides for a highly competitive and liquid market for oil sales.

In February 2007, we entered into a letter agreement with ETC Texas Pipeline, Ltd. that expands our existing transportation and treating agreement to meet the future gathering, treating and transportation of natural gas produced and owned or controlled by us in the Hilltop area of East Texas. Under the letter agreement, ETC would construct a gathering system sufficient to gather and treat up to 150 MMcfd, and we would deliver to ETC a minimum of approximately 135 Bcf over a 10-year period. Minimum annual sales over the 10-year period and fees for the gathering and treating of natural gas are currently being negotiated.

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During 2006, ETC Texas Pipeline Ltd. and Enserco Energy, Inc. accounted for 63% and 25% of our natural gas and oil revenues, respectively. During 2005, ETC. and Enserco accounted for 65% and 26%, respectively, of our natural gas and oil revenues. During 2004, ETC and Western Gas Resources, Inc. accounted for 59% and 35%, respectively, of our natural gas and oil revenues. Although ETC is the major natural gas purchaser and transporter in the area of our deep Bossier play and limited natural gas purchaser and transporter alternatives are currently available in this area, management believes that other natural gas purchasers and transporters could ultimately be located thus minimizing a long-term material adverse impact on our financial condition or results of operations. Management believes that the loss of Enserco in the Powder River Basin would not have a long-term material adverse impact on our financial position or results of operations, as there are numerous other purchasers operating in the Powder River Basin.

Competition

The natural gas and oil industry is intensely competitive and speculative in all of its phases. We encounter competition from other natural gas and oil companies in all areas of our operations. In seeking suitable natural gas and oil properties for acquisition, we compete with other companies operating in our areas of interest, including large natural gas and oil companies and other independent operators, which have greater financial resources and in many instances, have been engaged in the exploration and production business for a much longer time than we have. Many of our competitors also have substantially larger operating staffs than we do. Many of these competitors not only explore for and produce natural gas and oil but also market natural gas and oil and other products on a regional, national or worldwide basis. These competitors may be able to pay more for productive natural gas and oil properties and exploratory prospects and define, evaluate, bid for and purchase a greater number of properties and prospects than us. In addition, these competitors may have a greater ability to continue exploration activities during periods of low market prices. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

The prices of our natural gas and oil production are controlled by market forces. However, competition in the natural gas and oil exploration industry also exists in the form of competition to acquire leases and obtain favorable transportation prices. We are relatively small and may have difficulty acquiring additional acreage and/or projects and may have difficulty arranging for the transportation of our production. We also face competition in obtaining natural gas and oil drilling rigs and in sourcing the manpower to run them and provide related services.

Governmental Regulation

In addition to the environmental regulations discussed below under the heading “Environmental Regulation”, our natural gas and oil exploration, production and related operations are subject to extensive rules and regulations promulgated in the United States and Australia. These laws and regulations, all of which are subject to change from time to time, include matters relating to land tenure; drilling and production practices such as discharge permits and the spacing of wells; the disposal of water resulting from operations and the processing, handling and disposal of hazardous materials such as hydrocarbons and naturally occurring radioactive materials; bonding requirements; ongoing obligations for licensing; reporting requirements; marketing and pricing policies; royalties; taxation; and foreign trade and investment.

Failure to comply with these rules and regulations can result in substantial penalties. Furthermore, we could be liable for personal injuries, property damage, spills, discharge of hazardous materials, reclamation costs, remediation, clean-up costs and other environmental damages as a consequence of acquiring a natural gas or oil opportunity.

The regulatory burden on the natural gas and oil industry increases our cost of doing business and affects our financial condition. Although we believe we are in substantial compliance with all applicable laws and regulations, we are unable to predict the future cost or impact of complying with such laws because those laws

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and regulations are frequently amended or reinterpreted. We are unable to predict what additional legislation or amendments may be proposed that will affect our operations or when any such proposals, if enacted, might become effective.

U.S. Governmental Regulation

Transportation and Sale of Natural Gas.    Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the regulations promulgated thereunder by the Federal Energy Regulatory Commission (FERC). In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of natural gas sales by producers began with the enactment of the Natural Gas Policy Act of 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining Natural Gas Act of 1938 and Natural Gas Policy Act of 1978 price and non-price controls affecting producer sales of natural gas effective January 1, 1993. Congress could, however, re-enact price controls in the future.

FERC regulates interstate natural gas pipeline transportation rates and service conditions, which affect the marketing of natural gas produced by us and the revenues received by us for sales of such natural gas. FERC requires interstate pipelines to provide open-access transportation on a non-discriminatory basis for all natural gas shippers. FERC frequently reviews and modifies its regulations regarding the transportation of natural gas with the stated goal of fostering competition within all phases of the natural gas industry. In addition, with respect to production onshore or in state waters, the intra-state transportation of natural gas would be subject to state regulatory jurisdiction as well.

Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective or their effect, if any, on our operations. The natural gas industry historically has been closely regulated; thus, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future. We do not believe that we will be affected by any action taken in a materially different way than other natural gas producers, gatherers and marketers with which we compete.

Federal Regulation of Sales and Transportation of Crude Oil.    Our sales of crude oil and condensate are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. Certain regulations implemented by FERC in recent years could result in an increase in the cost of pipeline transportation service. We do not believe, however, that these regulations affect us any differently than other producers.

Our operations are subject to extensive and continually changing regulation affecting the natural gas and oil industry. Many departments and agencies, both federal and state are authorized by statute to issue, and have issued, rules and regulations binding on the natural gas and oil industry and its individual participants. The failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability. We do not believe that we are affected in a significantly different manner by these regulations than are our competitors.

Regulation of Production.    The production of natural gas and oil is subject to regulation under a wide range of state and federal statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds, and reports concerning operations. Most states in which we own and operate properties, have regulations governing conservation matters, including provisions for the unitization or pooling of the natural gas and oil properties, the establishment of maximum rates of production from oil and natural gas wells, the spacing of wells, and the plugging and abandonment of wells and removal of related production equipment. Many states also restrict production to the market demand for the natural gas and oil and several states have indicated interests in revising applicable regulations. These regulations can limit the amount

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of the natural gas and oil we can produce from our wells, limit the number of wells, or limit the locations at which we can conduct drilling operations. Moreover, each state generally imposes a production or severance tax with respect to production and sale of natural gas, natural gas liquids and crude oil within its jurisdiction.

Australian Governmental Regulation

Commonwealth and State Laws and Regulations.    The regulation of the activities of participants in the natural gas and oil industry in Australia is similar to that of the United States, in that regulatory controls are imposed at both the state and commonwealth (federal) levels. Specific commonwealth regulations impose environmental, petroleum industry licensing, foreign investment, cultural heritage and native title restrictions on accessing resources in Australia. These regulations are in addition to any state level regulations.

Foreign Investment Regulation.    Foreign investment in Australia is regulated by the commonwealth through its foreign investment legislation and policy. In some circumstances, Australian foreign investment regulation and policy requires foreign interests to obtain prior approval from the Treasurer before investing in specific industry sectors. The Foreign Investment Review Board administers the regulation of foreign investment on behalf of the commonwealth. Its functions include analyzing proposals by foreign interests for investment in Australia and making recommendations to the Government on the compatibility of those proposals with Government policy and the relevant legislation. In some circumstances the acquisition of, investment in or formation of a new business will require review and approval under the commonwealth foreign investment policy and regulations.

Native title.    Australian law recognizes that in some instances native title, that is the laws and customs of the Aboriginal inhabitants, has survived European settlement. Native title will only survive if it has not been extinguished. Native title may be extinguished by an Act of Government, such as the creation of a title that is inconsistent with native title. This may include a grant of the right to exclusive possession through freehold title or lease. Native title may also be extinguished if the connection between the land and the group of Aboriginal people claiming native title has been lost. Native title legislation was enacted in 1993 in order to provide a statutory framework for deciding questions such as where native title exists, who holds native title and the nature of native title which were left unanswered by a landmark 1992 Australian High Court decision. Native title claims by Aboriginal groups can include claims over existing and potential natural gas and oil exploration and development areas. If we apply to the relevant State or Territory for an onshore exploration permit or production license over Crown land or “Aboriginal” land which has a registered native title claimant or a registered native title holder, we will have to go through a mandatory negotiation process, followed by an arbitration conducted by the National Native Title Tribunal if no agreement can be reached through negotiation. The results of the negotiation may impose significant financial obligations on us. Each application for an exploration permit, production license or a pipeline license must be examined individually in order to determine the existence of native title claims. Native title claims can impact the validity of any rights granted to us if they affect native title and have been granted other than in compliance with the Native Title Act 1993 (Cth) after 1993. Depending on the locality of a project other access rights form private or Crown land holders may also need to be obtained.

Australian Petroleum Regulation and Gas Markets.    All petroleum tenements in which we hold an interest are subject to specific licensing regulation in the relevant States. Each exploration permit or production license will (depending on the nature of the license and the State in which the project is located) be issued subject to various obligations. These may include obligations as to expenditure, payment of rent, consultation with occupiers and rehabilitation. These obligations must be met to maintain the good standing of the tenement Licenses may be cancelled or revoked for non compliance. In Australia the ownership of minerals (including petroleum) is vested in the Government (the Crown) and ownership only passes to the license holder once the relevant mineral is extracted. We are required to pay Government royalties of 10% of the wellhead value of petroleum extracted. Several statutory mechanisms regulate access rights to a range of infrastructure in Australia including gas transmission pipelines. These involve generic access regulations contained in the Trade Practices Act 1974 Cth. and industry specific schemes contained in specific legislative instruments, industry codes and schemes. Objectives of this regulatory regime include providing a process for establishing third party access to

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natural gas pipelines, facilitating the development and operation of a national natural gas market, promoting a competitive market for natural gas in which customers are able to choose their supplier, and providing a right of access to transmission and distribution networks on fair and reasonable terms and conditions. We cannot currently ascertain the impact of the regime objectives on our operations but believe it could benefit us.

Environmental Regulation

Our natural gas and oil exploration and production operations and similar operations that we do not operate but in which we own a working interest in the United States are subject to significant federal, state and local environmental laws and regulations governing environmental protection as well as the discharge of substances into the environment. These laws and regulations may restrict the types, quantities and concentrations of various substances that can be released into the environment as a result of natural gas and oil drilling, production and processing activities; suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands and other protected areas; require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells; and restrict injection of liquids into subsurface strata that may contaminate groundwater. Governmental authorities have the power to enforce compliance with their laws, regulations and permits, and violations may result in the issuance of injunctions limiting or prohibiting operations, as well as administrative, civil and even criminal penalties. The effects of these laws and regulations, as well as the assessment of other laws or regulations that are adopted in the future, could have a material adverse impact on our operations and other operations in which we own an interest. As discussed below, our Australian operations are similarly subject to regulation by Australian authorities.

We believe that we are in substantial compliance with existing applicable environmental laws and regulations. However, it is possible that new environmental laws and regulations or the modification or more stringent enforcement of existing laws and regulations could have a material adverse effect on our operations and other operations in which we own an interest. As a general matter, the recent trend in environmental legislation and regulation is toward stricter standards, and this trend will likely continue. To date, we have not been required to expend significant resources in order to satisfy existing applicable environmental laws and regulations. However, there is no assurance that costs to comply with existing and any new environmental laws and regulations in the future will not be material. In addition, if substantial liabilities to third parties or governmental entities are incurred, the payment of such claims may reduce or eliminate the funds available for project investment or result in loss of our properties. Moreover, a serious incident of pollution may result in the suspension or cessation of operations in the affected area. Although we maintain insurance coverage against costs of clean-up operations, no assurance can be given that we are fully insured against all such potential risks. The imposition of any of these liabilities or compliance obligations on us may have a material adverse effect on our financial condition and results of operations.

The following is a summary of some of the existing environmental laws, rules and regulations to which our business operations are subject.

U.S. Environmental Regulations

In the United States, environmental laws are implemented principally by the United States Environmental Protection Agency, or EPA, the Department of Transportation and the Department of the Interior, as well as other comparable state agencies.

Comprehensive Environmental Response, Compensation and Liability Act.    The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes strict, joint and several liability without regard to fault or legality of conduct, on persons who are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance released at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring land

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owners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Although CERCLA currently excludes “petroleum” and “natural gas, natural gas liquids, liquefied natural gas or synthetic gas useable for fuel,” from the definition of “hazardous substance”, our operations as well as other operations in which we own an interest may generate materials that are subject to regulation as hazardous substances under CERCLA.

CERCLA may require payment for cleanup of certain abandoned waste disposal sites, even if such waste disposal activities were undertaken in compliance with regulations applicable at the time of disposal. Under CERCLA, one party may, under certain circumstances, be required to bear more than its proportional share of cleanup costs if payment cannot be obtained from other responsible parties. CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. The scope of financial liability under these laws involves inherent uncertainties.

Resource Conservation and Recovery Act.    The Resource Conservation and Recovery Act, or RCRA, and comparable state programs regulate the management, treatment, storage and disposal of hazardous and non-hazardous solid wastes. Our operations and other operations in which we own an interest generate wastes, including hazardous wastes that are subject to RCRA and comparable state laws. We believe that these operations are currently complying in all material respects with applicable RCRA requirements. Although RCRA currently exempts certain natural gas and oil exploration and production wastes from the definition of hazardous waste, we cannot assure you that this exemption will be preserved in the future, which could have a significant impact on us as well as of the natural gas and oil industry in general.

We currently own, lease, own a working interest in, or operate numerous properties that for many years have been used by third parties for the exploration and production of natural gas and oil. Although we abide by standard industry operating and disposal practices, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us or in which we own an interest, or on or under other locations, including off-site locations, where such substances have been taken for disposal or recycling. In addition, many of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes (including substances disposed of or released by prior owners or operators), remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges.    Our operations and other operations in which we own a working interest are subject to the Clean Water Act, or CWA, as well as the Oil Pollution Act, or OPA, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States, including wetlands. Under the CWA and OPA, any unpermitted release of pollutants from operations could cause us to become subject to the costs of remediating a release; administrative, civil or criminal fines or penalties; or OPA specified damages, such as damages for loss of use and natural resource damages. In addition, in the event that spills or releases of produced water from natural gas and oil production operations were to occur, we would be subject to spill notification and response requirements under the CWA or the equivalent state regulatory program. Depending on the nature and location of these operations, spill response plans may also have to be prepared.

Our natural gas and oil exploration and production operations and other operations in which we own an interest generate produced water as a waste material, which is subject to the disposal requirements of the CWA, Safe Drinking Water Act, or SDWA, or an equivalent state regulatory program. Naturally occurring groundwater is also typically produced by CBM production in our operations or in other operations in which we own an interest. This produced water is disposed of by re-injection into the subsurface through disposal wells, discharge to the surface, or in evaporation ponds. Whichever disposal method is used, produced water must be disposed of in compliance with permits issued by regulatory agencies, and in compliance with applicable environmental

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regulations. This water can sometimes be disposed of by discharging it under discharge permits issued pursuant to the CWA or an equivalent state program. Another common method of produced water disposal is subsurface injection in disposal wells. Such disposal wells are permitted under the SDWA, or an equivalent state regulatory program. To date, we believe that all necessary surface discharge or disposal well permits have been obtained and that the produced water has been discharged into the produced water disposal wells in substantial compliance with such obtained permits and applicable laws. Nonetheless, in connection with CBM production in the Powder River Basin, a concern common to many operators in the basin is the potential for opposition by individuals or groups to the issuance of a permit for the discharge or disposal of water generated by production activities. Such opposition could result in delays, limitations, or denials with respect to environmental or other approvals necessary to develop our acreage in the Powder River Basin, which could adversely affect our financial condition or results of operations.

Air Emissions.    The Clean Air Act, or CAA, and comparable state laws and regulations govern emissions of various air pollutants through the issuance of permits and the imposition of other requirements. Air emissions from some equipment found at our operations or other operations in which we own an interest, such as gas compressors, are potentially subject to regulations under the Clean Air Act or equivalent state and local regulatory programs, although many small air emission sources are expressly exempt from such regulations. To the extent that these air emissions are regulated, they are generally regulated by permits issued by state regulatory agencies. To date, we believe that no unusual difficulties have been encountered in obtaining air permits. However, there is no assurance in the future, we will not be required to incur capital expenditures in connection with maintaining or obtaining operating permits and approvals addressing air emission-related issues.

CBM production operations involve the use of gas-fired compressors to transport gas that is produced. Emissions of combustible by-products from compressors at one location may be large enough to subject the compressors to CAA and comparable state air quality regulation requirements for pre-construction and operating permits. To date, we believe that such gas-fired compressors operated by us or at other operations in which we own a working interest have been operated in substantial compliance with obtained permits and the applicable federal, state and local laws and regulations without undue cost to or burden on our business activities. Another air emission associated with these CBM operations that may be subject to regulation and permitting requirements is particulate matter resulting from construction activities and vehicle traffic. To date, we do not believe there has been any unusual difficulty in complying with requirements related to particulate matter.

Other Laws and Regulations.    Our operations and other operations in which we own a working interest are also impacted by regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials. Furthermore, owners, lessees and operators of natural gas and oil properties are also subject to increasing civil liability brought by surface owners and adjoining property owners. Such claims are predicated on the damage to or contamination of land resources occasioned by drilling and production operations and the products derived therefrom, and are often based on negligence, trespass, nuisance, strict liability or fraud.

In response to recent studies suggesting that emissions of certain gases including carbon dioxide, may be contributing to warming of the Earth’s atmosphere, many foreign nations have agreed to limit emissions of these gases, generally referred to as “greenhouse gases”, pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol”. Although the United States is not participating in the Kyoto Protocol, the current session of Congress is considering climate change legislation, with multiple bills having already been introduced in the Senate that propose to restrict greenhouse gas emissions. By comparison, several states have already adopted legislation, regulations and/or regulatory initiatives to reduce emissions of greenhouse gases. Also, on November 29, 2006, the U.S. Supreme Court heard arguments on a case appealed from the U.S. Circuit Court of Appeals for the District Columbia, Massachusetts, et al. v. EPA, in which the appellate court held that the U.S. Environmental Protection Agency had discretion under the federal Clean Air Act to refuse to regulate carbon dioxide emissions from mobile sources. Passage of climate change legislation by Congress or a Supreme Court reversal of the appellate decision could result in federal regulation of carbon dioxide emissions and other greenhouse gases. In particular, the natural gas and oil exploration and production industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations and other operations in which

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we own an interest currently are not adversely impacted by current federal, state and local climate change initiatives; however, it is not possible to accurately estimate how potential future laws and regulations restricting emissions of greenhouse gases in areas of the United States in which we conduct business would adversely affect our operations and other operations in which we own an interest.

Finally, legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations and the operations of the natural gas and oil industry in general may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Australian Environmental Regulations

Australia has environmental laws and regulations that are similar in scope and impact to United States environmental laws and regulations. Similar approval, licensing and operational impacts apply at a commonwealth, state and local government level. As a result, environmental laws and regulations can result in similar licensing and operational impacts in Australia that are similar to those discussed above with respect to the United States.

The legislation regulating environmental assessment at a commonwealth level is the Environmental Protection and Biodiversity Conservation Act 1999 (Cth.). This Commonwealth Act establishes a regime for protecting the environment, flora and fauna biodiversity and Australian national heritage. It requires any person taking an action which could have a significant impact on one of these values to refer it to the commonwealth Minister for the Environment for consideration and potential assessment. The Act only applies to matters of national environmental or heritage significance. These are matters which impact on a world heritage site, Ramsar wetlands, species which are listed as threatened under the Act, migratory species, nuclear actions and commonwealth marine areas or places listed on the commonwealth heritage list. Operators are required to assess their projects to determine whether an action is likely to have a significant impact on matters of national environmental significance, and make a decision respecting submission of that assessment to a public referral process. The referral is expected to add time to the existing approval process but its effect on a project will depend on the significance of the impact identified. In addition, see the discussion in “Business—Gunnedah Basin, New South Wales, Australia” for a discussion of the New South Wales government’s bioregion study involving PEL 238.

Environmental protection and planning issues are also regulated in each State and Territory by specific legislation enacted by each State or Territory. The governments of New South Wales and Victoria both have a suite of legislation regulating environmental matters in their States. Generally speaking, onshore natural gas and oil projects in New South Wales and Victoria require an environmental approval from the State (and sometimes Commonwealth) Government, land use planning approval from local government and an approval under the relevant petroleum regime (as referred to above. Legislation provides for the integrated assessment of these issues. The environmental regulators in both New South Wales and Victoria have the ability to require a project operator to prepare and implement a plan to improve the environmental performance of a project, and may also amend the conditions on an existing environmental approval. As such, the environmental regulation of a project may not be assumed to remain static following approval, and may become more onerous over time. The legislation imposes a licensing approval and contamination management scheme which may impact on our operations and impose a liability which may extend beyond the time period during which properties are operated, occupied or owned. The laws and regulations also restrict emissions to air, land and water and may control or regulate substances which can be released into the environment and the manner in which they are transported and disposed of. Approvals will usually include terms which require remediation and reinstatement obligations for the site during the course of operations and following closure of the project.

Australian laws and regulations protecting archeological relics, cultural, natural and built heritage as well as native flora and fauna can also impact on our operations and impose obligations in respect of restitution or

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replacement, as well as liability in respect of damage. In particular, indigenous cultural heritage protection laws are becoming increasingly stringent and in many States and the Northern Territory the specialist indigenous heritage protection laws require a proponent to negotiate directly with indigenous groups with respect to a major project.

Employees

As of March 20, 2007, we had 19 employees, all of whom are full time. We use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, regulatory reporting, environmental and tax services. On those properties where we are not the operator, we rely on outside operators to drill, produce and market our natural gas and oil. Our employees do not belong to a union or have a collective bargaining organization. Management considers its relationship with employees to be good.

Corporate Offices

We lease our corporate offices at 1331 Lamar Street, Suite 1080, Houston, Texas 77010. Our office space covers 9,332 square feet at a monthly rental of $17,100 through October 2010. During 2006, we maintained an office in Miami, Florida (our Chief Executive Officer’s city of residence) at a monthly rental of $2,700 per month.

Internet Website Access

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”) are made available free of charge on our internet website at www.gastar.com as soon as reasonably practicable after we have electronically filed the material with, or furnished it to, the SEC. The public may read and copy any materials we have filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet website that contains our reports, proxy and information statements and our other SEC filings. The address of that site is www.sec.gov. Information is also available at www.sedar.com for our filings required by Canadian securities regulators and the Toronto Stock Exchange. None of the information on our internet website or filed by us on www.sedar.com should be considered incorporated into, or considered a part of, this report.

We also make available free of charge on our internet website at www.gastar.com our:

Risk Factors Related to Our Business

In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following material risk factors associated with our business and our common shares when evaluating Gastar. An investment in Gastar is subject to risks inherent in our business. The trading price of our common shares will be affected by the performance of our business relative to, among other things, competition, market conditions and general economic and industry conditions. The value of an investment in Gastar may decrease, resulting in a loss.

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Natural gas and oil prices are volatile and a decline in natural gas and oil prices can significantly affect our financial condition and results of operations.

The success of our business greatly depends on market prices of natural gas and oil. The higher market prices are, the more likely it is that we will be financially successful. On the other hand, declines in natural gas or oil prices may have a material adverse affect our financial condition, profitability and liquidity. Lower prices also may reduce the amount of natural gas or oil that we can produce economically. Natural gas and oil are commodities whose prices are set by broad market forces. Historically, the natural gas and oil markets have been volatile. Natural gas and oil prices will likely continue to be volatile in the future. Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas or oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include:

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 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. Low natural gas prices in any or all of the areas where we operate would negatively impact our financial condition and results of operations.

Natural gas and oil reserves are depleting assets, and the failure to replace our reserves would adversely affect our production and cash flows.

Our future natural gas and oil production depends on our success in finding or acquiring new reserves. If we fail to replace reserves, our level of production and cash flows would be adversely impacted. Production from natural gas and oil properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. If we are not successful, our future production and revenues will be materially adversely affected.

Exploration is a high risk activity, and our participation in drilling activities may not be successful.

Our future success will largely depend on the success of our exploration drilling program. Participation in exploration drilling activities involves numerous risks, including the risk that no commercially productive natural

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gas or oil reservoirs will be discovered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

We use available seismic data to assist in the location of potential drilling sites. Even when properly used and interpreted, 2-D and 3-D seismic data and other visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. Poor results from our drilling activities would have a material adverse affect our financial condition, future cash flows and results of operations. In addition, using seismic data and other advanced technologies involves substantial upfront costs and is more expensive than traditional drilling strategies, and we could incur losses as a result of these expenditures.

We have incurred significant net losses since our inception and may incur additional significant net losses in the future.

We have not been profitable since we started our business. We incurred net losses of $84.8 million and $25.7 million for the years ended December 31, 2006 and 2005, respectively. Our capital has been employed in an increasingly expanding natural gas and oil exploration and development program with the focus on finding significant natural gas and oil reserves and producing from them over the long-term rather than focusing on achieving immediate net income. The uncertainties described in this section may impede our ability to ultimately find, develop and exploit natural gas and oil reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future.

Our level of indebtedness reduces our financial and operational flexibility, and our level of indebtedness may increase.

As of December 31, 2006, the principal amount of our long-term debt was $106.3 million. Our level of indebtedness affects our operations in several ways, including the following:

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We may incur additional debt, including significant additional secured indebtedness, in order to develop our properties in accordance with our business plan for the next twelve months. A higher level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, natural gas and oil prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flow to pay the interest on our debt and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

Disputes have arisen between the Company and Geostar in connection with the POA and general operating and administrative activity,

Over the past six years, we have entered into various transactions or agreements with Geostar, a related party. In 2001, the Company entered into a Participation and Operating Agreement (the “POA”) with Geostar that governed the joint Geostar and Company United States and Australian property acquisition and exploration and development activities. We have also requested that Geostar’s Australian subsidiary provide a record title assignment of our beneficial interests in EL 4416, the exploration license in the Gippsland Basin property in Victoria, Australia. Various disputes have arisen, primarily over the past year, in connection with the POA and general operating and administrative activity between Geostar and us, including claims by Geostar that we owe Geostar approximately $3.0 million of additional charges for operating and administrative costs not previously billed and approximately $11.0 million in demands for finder fees for funds previously provided by Geostar on our behalf. Although we strongly contend that these additional Geostar charges are without merit and that Geostar owes us approximately $3.8 million at December 31, 2006, we may not prevail. Payment to Geostar of the amounts asserted would have a material adverse effect on our financial position.

Deficiencies of title to our leased interests could significantly affect our financial condition.

Our practice in acquiring exploration leases or undivided interests in natural gas and oil leases is not to incur the expense of retaining lawyers to examine the title to the mineral interest prior to executing the lease. Instead, we rely upon the judgment of lease brokers and others to perform the field work in examining records in the appropriate governmental or county clerk’s office before leasing a specific mineral interest. This practice is widely followed in the industry. Prior to the drilling of an exploration well, the operator of the well will typically obtain a preliminary title review of the drillsite lease and/or spacing unit within which the proposed well is to be drilled to identify any obvious deficiencies in title to the well and, if there are deficiencies, to identify measures necessary to cure those defects to the extent reasonably possible. However, such deficiencies may have been cured by the operator of any such wells. It does happen, from time to time, that the examination made by the title lawyers reveals that the lease or leases are invalid, having been purchased in error from a person who is not the rightful owner of the mineral interest desired. In these circumstances, we may not be able to proceed with our exploration and development of the lease site or may incur costs to remedy a defect, which could affect our financial condition and results of operations. Information about our legal proceedings is set forth in Footnote 16 “Commitments and Contingencies—Litigation” to our consolidated financial statements, which begins on page F-1.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present values of our reserves.

The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant

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inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves.

There are many uncertainties inherent in estimating natural gas and oil reserves and their values, many of which are beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas or oil that cannot be measured in an exact manner. Estimates of economically recoverable natural gas or oil reserves and of future net cash flows necessarily depend on many variables and assumptions, such as:

Any of these assumptions could vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of natural gas or oil attributable to any particular group of properties, classifications of those reserves based on risk recovery and estimates of the future net cash flows expected from them prepared by different engineers, or by the same engineer at different times, may vary substantially. Because of this, our reserve estimates may materially change at any time.

You should not consider the present values of estimated future net cash flows referred to in this Form 10-K to be the current market value of the estimated reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are generally based on prices and costs in effect when the estimate is made. However, actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:

In this Form 10-K, the net present value of future net revenues is calculated using a 10% discount rate. This rate is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the natural gas and oil industry in general.

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, write downs in the future may be required as a result of factors that may negatively affect the present value of proved natural gas and oil reserves. 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.

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A majority of our proved reserves are classified as proved developed non-producing and proved undeveloped and may ultimately prove to be less than estimated.

At December 31, 2006, approximately 63.5% of our total proved reserves were classified as proved developed non-producing and proved undeveloped. It will take substantial capital to recomplete or drill our non-producing and undeveloped locations. Our estimate of proved reserves at December 31, 2006 assumes that we will spend significant development capital expenditures to develop these reserves, including an estimated $30.9 million in 2007. Further, our drilling efforts may be delayed or unsuccessful, and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition and results of operations.

We may experience shortages of equipment and personnel, which could significantly disrupt or delay our operations.

From time to time, there has been a general shortage of drilling rigs, equipment, supplies and oilfield services in North America and Australia, which could intensify with increased industry activity. In addition, the costs and delivery times of rigs, equipment and supplies have risen. Shortages of drilling rigs, equipment, supplies or trained personnel could delay and adversely affect our operations and drilling plans, which could have an adverse effect on our results of operations. While we intend to enter into contracts for the services of drilling rigs in North America and Australia, we may not be successful in doing so. The demand for, and wage rates of, qualified rig crews have begun to rise in the drilling industry due to the increasing number of active rigs in service. Personnel shortages have occurred in the past during times of increasing demand for drilling services. If the number of active drilling rigs increases, we may experience shortages of qualified personnel to operate our drilling rigs, which could delay our drilling operations and adversely affect our business.

We are subject to complex laws and regulations, including environmental laws and regulations that can adversely affect the cost, manner or feasibility of conducting our business.

Our exploration and production interests and operations are subject to stringent and complex federal, state and local laws and regulations governing the operation and maintenance of our facilities and the handling and discharge of substances into the environment. These existing laws and regulations impose numerous obligations that are applicable to our interests and operations including:

In addition, regulatory agencies have from time to time imposed price controls and limitations on production by restricting the flow rate of wells below actual production capacity in order to conserve supplies of natural gas and oil.

Failure to comply with environmental and other laws and regulations applicable to our interests and operations could result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of orders enjoining or limiting future operations, any of which could have a material adverse affect on our financial condition. Legal requirements are sometimes unclear or subject to reinterpretation and may be frequently changed in response to economic or political conditions. As a result, it is hard to predict the ultimate cost of compliance with these requirements or their affect on our interests and operations. In addition, existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations may have a material adverse affect on our financial condition and results of operations.

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The production, handling, storage, transportation and disposal of natural gas and oil, by-products of natural gas and oil and other substances produced or used in connection with natural gas and oil production operations are regulated by laws and regulations focused on the protection of human health and the environment. Joint and several, strict liability may be incurred without regard to fault, or the legality of the original conduct, under certain of these laws and regulations for the remediation of contaminated areas. Private parties, including the owners of properties located near our storage facilities or through which our pipeline systems pass, also may have the right to pursue legal actions to enforce compliance, as well as seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. Consequently, the discharge or release of natural gas, oil or other substances into the air, soil or water, even by predecessor operators, could subject us to liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property and natural resource damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover some or any of these costs from insurance.

Our Australian operations are subject to unique risks relating to Aboriginal land claims and government licenses.

Our Australian operations could be affected by native title claims by Aboriginal groups. Australian law recognizes that in some instances native title, that is the laws and customs of the Aboriginal inhabitants, has survived European settlement. Native title will only survive if it has not been extinguished. Native title may be extinguished by an Act of Government, such as the creation of a title that is inconsistent with native title. This may include a grant of the right to exclusive possession through freehold title or lease. Native title may also be extinguished if the connection between the land and the group of Aboriginal people claiming native title has been lost. Each authority to prospect, and license in areas in which we desire to engage in exploration or production activities must be examined individually in order to determine the validity of any native title claim. We may be required to negotiate with any Aborigines who can make a valid claim to having ancestral ties to the areas in which we desire to engage in exploration or production activities. These negotiations could both delay the timing of our exploration or production activities, as well as add an additional layer of cost or a requirement to share revenues if any Aboriginal claimants are proved to have native title rights in the exploration areas. Approximately 27.5% of our Gippsland Basin property in Victoria may be subject to native title claims. We have been informed by the government of New South Wales that the proportion of land within PEL 238 in the Gunnedah Basin, New South Wales, which is potentially subject to native title claims, cannot be readily determined.

The process of drilling for and producing natural gas and oil involves many operating risks that can cause substantial losses, and we may not have enough insurance to cover these risks adequately.

The natural gas and oil business involves many operating hazards, such as:

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Any of these events could cause substantial losses to us as a result of:

We could also be responsible for environmental damage caused by previous owners of property that we purchase or lease. As a result, we may incur substantial liabilities to third parties or governmental entities. Although we maintain what we believe is appropriate and customary insurance for these risks, the insurance may not be available or sufficient to cover all of these liabilities. If these liabilities are not covered by our insurance, paying them could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties.

Approximately 66% 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. 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. 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.

There are a limited number of natural gas purchasers and transporters in the Hilltop area of our deep Bossier play in East Texas. The loss of our current purchaser and transporter and an inability to locate another purchaser and transporter would have a material adverse effect on our financial condition and results of operations.

There are a limited number of natural gas purchasers and transporters in the Hilltop area of the deep Bossier play in East Texas. During 2006, ETC Texas Pipeline, Ltd. accounted for substantially all of our revenues from our deep Bossier play in East Texas. If ETC were to cease purchasing and transporting our natural gas and we were unable to contract with another purchaser and transporter, it would have a material adverse effect on our financial condition and results of operations.

Our ability to market our natural gas and oil may be impaired by capacity constraints on the gathering systems and pipelines that transport our natural gas and oil.

The availability of a ready market for our natural gas production depends on the proximity of our reserves to and the capacity of natural gas gathering systems, pipelines and trucking or terminal facilities. We enter into agreements with companies that own pipelines used to transport natural gas from the wellhead to contract destination. Those pipelines are limited in size and volume of natural gas flow. Should production begin, other outstanding contracts with other producers and developers could interfere with our access to a natural gas line to deliver natural gas to the market. We do not own or operate any natural gas lines or distribution facilities. Further, interstate transportation and distribution of natural gas is regulated by the federal government through the Federal Energy Regulatory Commission, or FERC. FERC sets rules and carries out administratively the oversight of interstate markets for natural gas and other energy policy. Among FERC’s powers is the ability to dictate sale and delivery of natural gas to any markets it oversees.

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Additionally, state regulators have vast powers over sale, supply and delivery of natural gas and oil within their state borders. While we do employ certain companies to represent our interests before state regulatory agencies, our interests may not receive favorable rulings from any state agency, or some future occurrence may drastically alter our ability to enter into contracts or deliver natural gas to the market.

Competition in the natural gas and oil industry is intense. We are smaller and have a more limited operating history than most of our competitors, and increased competitive pressure could adversely affect our results of operations.

We operate in a highly competitive environment. We compete with other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Our competitors include major integrated natural gas and oil companies, numerous independent natural gas and oil companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies that have substantially larger operating staffs and greater capital resources than we do and that, in many instances, have been engaged in the natural gas and oil business for a much longer time than we have. These companies may be able to pay more for exploratory prospects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase more properties and prospects than our financial and human resources permit. In addition, these companies may be able to spend more on the existing and changing technologies that we believe are and will be increasingly important to the current and future success of natural gas and oil companies. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. Increased competitive pressure could adversely affect our financial condition and results of operations.

Acquisition prospects are difficult to assess and may pose additional risks to our operations.

Where appropriate, we may evaluate and pursue acquisition opportunities on terms our management considers favorable. In particular, we expect to pursue acquisitions that have the potential to economically increase our natural gas and oil reserves. The successful acquisition of natural gas and oil properties requires an assessment of:

In connection with such an assessment, we would expect to perform a review of the subject properties that we believe to be generally consistent with industry practices. Nonetheless, the resulting conclusions are inexact and their accuracy inherently uncertain, and such an assessment may not reveal all existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every platform or well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Future acquisitions could pose additional risks to our operations and financial results, including:

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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, 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:

Technological changes could affect our operations.

The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement such new technologies at substantial costs. In addition, other natural gas and oil companies have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may be unable to respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost. One or more of the technologies that we currently use or may implement in the future may become obsolete.

Rapid growth could result in a strain on our resources.

Because of our size, our growth, if achieved, will likely place a significant strain on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of experienced managers, geoscientists and engineers, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

Our ability to successfully execute and maximize our business plan is dependent on our ability to obtain adequate financing.

In order to maximize our business plan, we will need to raise at least $50.0 million of new capital to develop our properties in accordance with our business plan for the next twelve months. Our business plan, which includes participation in 3-D seismic shoots, the drilling of exploration prospects and development projects and producing property acquisitions, has required and will continue to require substantial capital expenditures. We will require additional financing to fund our planned growth. Our ability to raise additional capital will depend on the results of our operations and the status of various capital and industry markets at the time we seek such capital. Accordingly, we cannot be certain that additional financing will be available to us on acceptable terms, if at all. In particular, the terms of our senior secured notes limit our ability to incur additional indebtedness. In the event additional capital resources are unavailable, we may be required to curtail our exploration and development activities or be forced to sell some of our assets in an untimely fashion or on less than favorable terms.

Not hedging our production may result in losses.

We currently do not hedge our natural gas and oil production. By not hedging our production, we may be more adversely affected by declines in natural gas and oil prices than our competitors who engage in hedging

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arrangements. Further, should we elect to hedge in the future, such hedges may result in us receiving lower than current prevailing market prices and place additional financial strains on us due to having to post margin calls on our hedges.

Exchange rate fluctuations subject us to unique risks.

As our Australian activities increase, we will be increasingly exposed to the impact of fluctuations in the exchange rate between the Australian dollar and the U.S. dollar. We have only minimal exposure to Canadian currency fluctuations, as almost all of our current revenues and expenses are in U.S. dollars.

We depend on our key personnel, the loss of which could adversely affect our operations and financial performance.

We depend to a large extent on the services of a limited number of senior management personnel and directors. Particularly, the loss of the services of our chief executive officer and chief financial officer could negatively impact our future operations. We have employment contracts with these key members of our senior management team; although, we do not maintain key-man life insurance on any of our senior management. We believe that our success is also dependent on our ability to continue to retain the services of skilled technical personnel. Our inability to retain skilled technical personnel could have a material adverse effect on our business.

Our major shareholder may influence the activities and operations of certain jointly owned properties, which also could result in conflicts of interest.

As of December 31, 2006, Chesapeake Energy Corporation owned approximately 16.5% of our outstanding common shares. As a result, Chesapeake is in a position to heavily influence the outcome of matters requiring a shareholder vote, including the election of directors, the adoption or amendment of provisions in our Amended and Restated Articles of Incorporation and Bylaws and the approval of mergers and other significant corporate transactions. Their high level of ownership may also delay, defer or prevent a change in control of us and may adversely affect the voting and other rights of other shareholders. Chesapeake has the right to have present an observer at our board of directors meetings.

Chesapeake and its subsidiaries are also engaged in the natural gas and oil business. Although we have entered into a joint operating agreement with Chesapeake, it is possible that we may in some circumstances be in direct or indirect competition with Chesapeake, including competition with respect to certain business strategies and transactions that we may propose to undertake. These conflicts of interest may have a material adverse affect our results of operations.

Some of our directors may not be subject to suit in the United States.

Two of our directors reside in Canada. As a result, it may be difficult or impossible to effect service of process within the United States upon those directors, to bring suit against them in the United States or to enforce in the United States courts any judgment obtained there against them predicated upon any civil liability provisions of the United States federal securities laws. Investors should not assume that Canadian courts (a) will enforce judgments of United States courts obtained in actions against those directors predicated upon the civil liability provisions of the United States federal securities laws or the securities or “blue sky” laws of any state within the United States; or (b) will enforce, in original actions, liabilities against those directors upon the United States federal securities laws or any such state securities or blue sky laws.

If we are unable to meet the SEC’s requirements related to the assessment, attestation and effectiveness of our internal controls, we may suffer a loss of investor confidence, and the price of our common shares may be adversely affected.

Under the Securities Exchange Act, we will be required to include in our annual report a report on internal controls over financial reporting. This report must state management’s responsibility for establishing and

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maintaining an adequate internal control structure and procedures for financial reporting. The report must also contain an assessment as of the end of the year of the effectiveness of those internal controls. The Exchange Act also requires our registered public accounting firm to test and report on the assessment made by management. These new rules will become effective for us for the year ending December 31, 2007. In order to meet these requirements, we must document and test the effectiveness of our internal controls and then allow time for our registered public accounting firm to audit our internal control structure. The amount of work required by us to prepare, maintain and test our internal control structure could be extensive. In the event that management is unable to complete its assessment of the effectiveness of our internal controls over financial reporting or our auditors are unable to attest to management’s assessment or do their own assessment, or if these internal controls are not effective, we might experience an adverse reaction in the financial marketplace due to a loss of investor confidence in the reliability of our financial statements, which could negatively impact the market price of our common shares.

Risk Factors Related to Our Common Shares

Our common share price has been and is likely to continue to be highly volatile.

The trading price of our common shares are subject to wide fluctuations in response to a variety of factors, including quarterly variations in operating results, announcements of drilling and rig activity, economic conditions in the natural gas and oil industry, general economic conditions or other events or factors that our beyond our control. Information about the market price of our common shares since trading commenced on the American Stock Exchange on January 5, 2006 is set forth in Item 5. “Market for Registrant’s Common Equity and Related Shareholder Matters and Issuer Purchases of Equity Securities—Market Information”.

In addition, the stock market in general and the market for natural gas and oil exploration companies in particular have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating results or asset values of those companies. These broad market and industry factors may seriously impact the market price and trading volume of our common shares regardless of our actual operating performance. In the past, following periods of volatility in the overall market and in the market price of a company’s securities, securities class action litigation has been instituted against these companies. If this type of litigation were instituted against us following a period of volatility in our common shares trading price, it could result in substantial costs and a diversion of our management’s attention and resources, which could have a materially adverse impact on our operations.

Future issuances of our common shares may adversely affect the price of our common shares.

The future issuance of a substantial number of common shares into the public market, or the perception that such issuance could occur, could adversely affect the prevailing market price of our common shares. A decline in the price of our common shares could make it more difficult to raise funds through future offerings of our common shares or securities convertible into common shares.

Our ability to issue an unlimited number of our common shares under our articles of incorporation may result in dilution or make it more difficult to effect a change in control of the company, which could adversely affect the price of our common shares.

Unlike most corporations formed in the United States, our Amended and Restated Articles of Incorporation chartered under the laws of the Province of Alberta, Canada permit the board of directors to issue an unlimited number of new common shares without shareholder approval, subject only to the rules of the American Stock Exchange and the Toronto Stock Exchange or any future exchange on which our common shares trades. The issuance of a large number of common shares could be effected by our directors to thwart a takeover attempt or offer for us by a third party, even if doing so would benefit our shareholders, which could result in the common shares being valued less in the market. The issuance, or the threat of issuance, of a large number of common

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shares, at prices that are dilutive to the outstanding common shares could also result in the common shares being valued less in the market.

Failure to register our common shares that were sold in a November 2006 private placement could result in us being required to pay fees, which could be significant.

On November 2006, we issued 25 million common shares for aggregate proceeds of $50.0 million. We are required to use our reasonable commercial efforts to file a registration statement with the SEC covering the resale of the common shares within 120 days of the November 2006 closing date and to use our reasonable commercial efforts to cause the registration statement to be declared effective within 180 days of the closing date. If a registration statement is not filed or declared effective within the time prescribed, we will be required to pay an amount in cash equal to 1.5% of the aggregate proceeds per month, up to aggregate payments of 8% of the aggregate proceeds, or $4.0 million, until the registration statement is declared effective or the common shares become freely tradable pursuant to Rule 144(k).

Issuance of the common shares upon exercise of warrants and conversion of convertible debentures, together with additional issuances of common shares to purchasers of our senior secured notes for no additional consideration, will dilute the ownership interest of existing shareholders and could adversely affect the market price of our common shares.

We are obligated to issue a substantial number of common shares upon exercise of outstanding common share purchase warrants and upon conversion of our convertible debentures. In connection with the issuance of $73.0 million of senior secured notes in June and September 2005, we issued 6,697,125 common shares to the purchasers of our senior secured notes pursuant subscription receipts. Additionally we have the right until June 2007 to issue an additional $10.0 million of senior secured notes, which would require the issuance of additional subscription rights. These issuances will dilute the ownership interest of existing shareholders. Any sales in the public market of the common shares issuable upon such exercise of warrants, conversion, or issuance of additional common shares could adversely affect prevailing market prices of our common shares. In addition, the existence of these warrants and convertible debentures may encourage short selling by market participants.

None.

Our properties consist primarily of natural gas, oil and mineral lease and concession interests in the following areas:

Additional information concerning our interests in these areas is described under Item 1. Business.

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Production, Prices and Operating Expenses

The following table presents information regarding the production volumes, average sales prices received and average production costs associated with our sales of natural gas and oil for the periods indicated. Oil and condensate are compared with natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil or condensate is the energy equivalent of six Mcf of natural gas.

Drilling Activity

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. “Undecided” 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.

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Exploration and Development Acreage

The following table sets forth our ownership interest in undeveloped acreage and developed acreage in the areas indicated where we own a working interest as of December 31, 2006. Gross represents the total number of acres in which we own a working interest. Net represents our proportionate working interest resulting from our ownership in gross acres.

Productive Wells

The following table sets forth our ownership interest in productive economic wells in the areas indicated where we own a working interest as of December 31, 2006, based on our third party reservoir engineering report. Gross represents the total number of wells in which we own a working interest. Net represents our proportionate working interest resulting from our ownership in gross wells. Productive wells are wells that are capable of producing natural gas or oil. Wells that are completed in more than one producing horizon are counted as one well.

As of December 31, 2006, we had no commercially productive wells in Australia.

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Natural Gas and Oil Reserves

Our estimated total net proved reserves of natural gas and oil as of December 31, 2006, and the present values of estimated future net revenues attributable to those reserves as of those dates, are presented in the following table. These estimates were prepared by Netherland, Sewell & Associates, Inc., independent reservoir engineers, and are part of their reserve reports on our natural gas and oil properties. Netherland, Sewell & Associates’ estimates were based on a review of geologic, economic, ownership and engineering data that we provided. In estimating the reserve quantities that are economically recoverable, end-of-period natural gas and oil prices, held constant, were utilized. In accordance with SEC regulations, no price or cost escalation or reduction was considered.

In accordance with SEC regulations, estimates of our proved reserves and future net revenues are made using sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties, except to the extent a contract specifically provides for escalation. Estimated quantities of proved reserves and future net revenues therefrom are affected by natural gas and oil prices, which have fluctuated significantly in recent years. Our estimated proved reserves have not been filed with or included in reports to any U.S. federal agency.

Pricing Assumptions

SEC regulations require that the natural gas and oil prices used in Netherland, Sewell & Associates’ reserve reports are the period-end prices for natural gas and oil at December 31, 2006. These prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve reports but are adjusted by lease for energy content, quality, transportation, compression and gathering fees, and regional price differentials. The pricing assumptions are listed below:

The weighted average natural gas and oil prices after basis adjustments used in our reserve valuation as of December 31, 2006 were $56.59 per barrel and $4.76 per Mcf.

The prices used in calculating the estimated future net revenue attributable to proved reserves do not reflect market prices for natural gas and oil production sold subsequent to December 31, 2006. There can be no assurance that all of the estimated proved reserves will be produced and sold at the assumed prices. Accordingly, the foregoing prices should not be interpreted as a prediction of future prices.

For additional information concerning our estimated proved reserves, the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2006, 2005 and 2004, and the changes in

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quantities and standardized measure of such reserves for each of the three years then ended, see Note 22 to our consolidated financial statements, which begins on page F-1.

Information about our legal proceedings is set forth in Footnote 16 “Commitments and Contingencies—Litigation” to our consolidated financial statements beginning on page F-1.

During the three months ended December 31, 2006, no matters were submitted to a vote of security holders.

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PART II

Market Information

Our common shares are traded on the American Stock Exchange under the symbol “GST” and the Toronto Stock Exchange under the symbol “YGA”.

The following table sets forth the high and low sale prices of our common shares as quoted in the United States over-the-counter market and, after January 5, 2006, as reported on the American Stock Exchange, and as reported on the Toronto Stock Exchange for the periods presented. The prices in the table below have been adjusted for stock splits.

The last reported sale prices of our common shares on the American Stock Exchange and the Toronto Stock Exchange on March 20, 2007 were $1.84 and CDN$2.00, respectively.

Shareholders

As of March 20, 2007, there were 641 shareholders of record who owned our common shares.

Dividends

We have never declared or paid any cash dividends on our common shares. We anticipate that we will retain any future earnings, if any, to satisfy our operational and other cash needs and do not anticipate paying any cash dividends on our common shares in the foreseeable future. In addition, our current senior secured notes contain covenants that prohibit us from paying cash dividends as long as such debt remains outstanding. Pursuant to the provisions of the Business Corporations Act (Alberta), we are prohibited from declaring or paying a dividend if there are reasonable grounds for believing that (1) we are, or would after the payment be, unable to pay our liabilities as they become due or (2) the realizable value of our assets would thereby be less than the aggregate of our liabilities and stated capital of all classes.

Recent Sales of Unregistered Securities; Use of Proceeds from Unregistered Securities

During the year ended December 31, 2006, we sold the following securities without registration under the Securities Act of 1933:

On February 3, 2006, the Company issued 21,948 common shares valued at $84,000 upon exercise of warrants at CDN$4.65 per share issued in connection with the sale of the Convertible Senior Debentures. The issuance of the common shares was exempt from registration pursuant to Section 3(a)(9) of the Securities Act of 1933.

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On March 20, 2006, the six-month anniversary of the September 19, 2005 $10.0 million Senior Secured Notes issuance, the Company issued to the note holders an additional 152,299 common shares valued at CDN$714,286. The issuance of the common shares was exempt from registration pursuant to Section 3(a)(9) of the Securities Act of 1933.

On March 31, 2006, in connection with the June 2005 purchase of properties from Geostar, the Company issued to Geostar as part of the final purchase price adjustment 548,128 common shares valued at CDN$4.50 per share, or $2.1 million. The issuance of the shares and unsecured subordinated notes to Geostar was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933.

On June 19, 2006, the twelve-month anniversary of the June 17, 2005 $63.0 million Senior Secured Notes issuance, the Company issued to the note holders an additional 1,607,143 common shares valued at CDN$4.5 million. The issuance of the common shares was exempt from registration pursuant to Section 3(a)(9) of the Securities Act of 1933.

On September 19, 2006, the twelve-month anniversary of the September 19, 2005 $10.0 million Senior Secured Notes issuance, the Company issued to the note holders an additional 256,016 common shares valued at CDN$714,286. The issuance of the common shares was exempt from registration pursuant to Section 3(a)(9) of the Securities Act of 1933.

On November 17, 2006, the Company issued 25,000,000 common shares to institutional investors valued at $50.0 million ($47.8 million after underwriting fees and related expenses). The issuance of the common shares was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933.

On December 18, 2006, the eighteen-month anniversary of the June 17, 2005 $63.0 million Senior Secured Notes issuance, the Company issued to the note holders an additional 1,800,000 common shares valued at CDN$4.5 million. The issuance of the common shares was exempt from registration pursuant to Section 3(a)(9) of the Securities Act of 1933.

On March 19, 2007, the eighteen-month anniversary of the September 19, 2005 $10.0 million Senior Secured Notes issuance, the Company issued to the note holders an additional 375,939 common shares valued at CDN$714,286. The issuance of the common shares was exempt from registration pursuant to Section 3(a)(9) of the Securities Act of 1933.

The following table presents selected historical financial data as of and for the periods indicated. The selected consolidated financial data as of and for the years ended December 31, 2006, 2005, 2004, 2003 and 2002 are derived from our audited consolidated financial statements.

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Additional pro forma information about the 2005 Geostar Acquisition is set forth in Footnote 5, “Geostar Acquisition” to our consolidated financial statements, which begins on page F-1.

The following discussion and analysis should be read in conjunction with accompanying consolidated financial statements and related notes included in Item 8. Financial Statements and Supplementary Data, which begins on page F-1. 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, changes due to the adoption of SASB 123(R), estimates of proved reserves, potential failure to achieve production from development projects, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this Form 10-K, 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 additional 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.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 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:

All other significant accounting policies that we employ are presented in the notes to the consolidated financial statements. The following discussion presents 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.

Full Cost Method of Accounting

We follow the full cost method of accounting for natural gas and oil operations, whereby all costs incurred in the acquisition, exploration and development of natural gas and oil reserves are initially capitalized into cost centers on a country-by-country basis. Our current cost centers are located in the United States and Australia. Such costs include land acquisition costs, geological and geophysical expenditures, carrying charges on

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non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities.

Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves, as determined by independent petroleum engineers. The percentage of total reserve volumes produced during the year is multiplied by the net capitalized investment plus future estimated development costs in those reserves.

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.

In applying the full cost method, we perform a quarterly ceiling test on the cost center properties whereby the net cost of natural gas and oil properties, net of related deferred income taxes (“net cost”), is limited to the sum of the estimated future net revenues from proved reserves using prices in effect at the end of the period held constant, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“ceiling”). If the net cost exceeds the ceiling, an impairment loss is recognized for the amount by which the net cost exceeds the ceiling and is shown as a reduction in natural gas and oil properties and as additional depletion. Proceeds from a sale of natural gas and oil properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion or amortization.

Natural Gas and Oil Reserves

Nature of Critical Estimate Item.    Our estimate of proved reserves is based on the quantities of natural gas and oil which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the economics of producing the reserves may change and therefore the estimate of proved reserves also may change. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent imprecision in these engineering estimates, our proved reserve volumes and values are used to calculate depletion and impairment provisions, respectively.

Assumptions/Approach Used.    Units-of-production method to amortize our natural gas and oil properties—The quantity of reserves could significantly impact our depletion expense. Any reduction in proved reserves without a corresponding reduction in capitalized costs will increase the depletion rate.

“Ceiling” Limitation Test—The full-cost method of accounting for natural gas and oil properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full-cost ceiling calculation. The ceiling is the discounted present value of our estimated total proved reserves using a 10% discount rate. To the extent that our capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense. Once incurred, this impairment of natural gas and oil properties is not reversible at a later date even if natural gas and oil prices increase. Impairments were required in the years ended December 31, 2006, and 2005. The calculation of our proved reserves could significantly impact our ceiling limitation used in determining whether an impairment of our capitalized costs is necessary. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are generally held constant indefinitely, but subsequent period end prices may be used if such prices would reduce the ceiling impairment. Therefore, the future net revenues associated with the estimated proved reserves are not based on our assessment

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of future prices or costs, but rather are based on prices and costs in effect at the time of evaluation. The weighted average natural gas and oil prices after basis adjustments used in the reserve valuations as of December 31, 2006 and 2005 were $54.85 per barrel and $6.11 per Mcf and $56.00 per barrel and $7.39 per Mcf, respectively.

Effect if different assumptions used.    Units-of-production method to amortize our natural gas and oil properties—A 10% increase in reserves would have decreased our depletion expense for the year ended December 31, 2006 by approximately 3%, while a 10% decrease in reserves would have increased our depletion expense by approximately 3% with an offsetting adjustment to ceiling impairment.

The most likely factor to contribute to a ceiling test impairment is the price used to calculate the reserve limitation threshold. A significant reduction in the prices at a future measurement date could trigger a full-cost ceiling impairment. A 10% decrease in prices would have resulted in the recognition of additional 2006 ceiling impairment expense of approximately $14.4 million. A 10% increase in prices used would have reduced our 2006 ceiling impairment expense by approximately $14.8 million.

Unproved Property Impairment

Nature of Critical Estimate Item.    We have elected to use the full-cost method to account for our natural gas and oil activities. Investments in unproved properties are not amortized until proved reserves associated with the properties can be determined or until impairment occurs. Unproved properties are evaluated quarterly for impairment on a field basis. If the results of an assessment indicate that an unproved property is impaired, the amount of impairment is added to the proved natural gas and oil property costs to be amortized.

Assumptions/Approach Used.    At December 31, 2006, we had $81.5 million allocated to unproved United States property costs which was comprised primarily of unevaluated acreage costs. The unproven property costs are evaluated by the technical team and management of whether the property has potential attributable reserves. Therefore, the assessment made by our technical team and management of the potential reserves will determine whether costs are moved from the unproved category to the full-cost pool for depletion or whether an impairment is taken.

Effect if different assumptions used.    A 10% increase or decrease in the unproved property balance would have decreased or increased our depletion expense by approximately 2% for the year ended December 31, 2006. A 10% decrease in unproved property balance would have increased our 2006 ceiling impairment expense by approximately $7.9 million.

Asset Retirement Obligation

Nature of Critical Estimate Item.    We have certain obligations to remove tangible equipment and restore land at the end of natural gas and oil production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells. Under Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations”, as discussed in Note 2 to our Consolidated Financial Statements, we estimate asset retirement costs for all of our assets, inflation adjust those costs to the forecast abandonment date, discount that amount using a credit-adjusted-risk-free rate back to the date we acquired the asset or obligation to retire the asset and record an ARO liability in that amount with a corresponding addition to our capitalized cost. We then accrete the liability quarterly using the period-end effective credit-adjusted-risk-free rate. As new wells are drilled or purchased, their initial asset retirement cost and liability is calculated and recorded. Should either the estimated life or the estimated abandonment costs of a property change upon our quarterly review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost (included in the full-cost pool);

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therefore, abandonment costs will almost always approximate the estimate. When wells are sold the related liability and asset costs are removed from the balance sheet.

Assumptions/Approach Used.    Estimating the future asset removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the estimate of the present value calculation of our AROs are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted-risk-free-rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments.

Effect if different assumptions used.    Since there are so 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 independent petroleum engineers, who have consented to the use of their name and reports in this Form 10-K, to evaluate our properties annually. We use the remaining estimated useful life from the year end reserve reports by our independent reserve engineer in 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.

Stock-Based Compensations

Effective January 1, 2003, we adopted the provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123), using the prospective application method of SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure”. This statement requires us to record compensation costs for options granted under our stock option plan in accordance with the fair value method prescribed in SFAS No. 123.

Prior to January 1, 2003, we accounted for stock options under the intrinsic value method of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” and its related interpretations. No compensation expense was recognized for stock options that had an exercise price equal to the market value of the underlying common stock on the date of grant. The fair values were determined by using the Black-Scholes-Merton valuation model.

Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS 123(R), “Share-Based Payment”, using the modified-prospective method. Under that method, compensation cost for 2006 includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of, January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (b) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS 123(R). Compensation expense is recognized on a straight-line basis over the options estimated lives for fixed awards with ratable vesting provisions.

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Results of Operations

The following is a comparative discussion of the results of operations for the years ended December 31, 2006, 2005 and 2004. It should be read in conjunction with the consolidated financial statements and the related notes in Item 8. Financial Statements and Supplementary Data, which begins on page F-1.

Year Ended December 31, 2006 compared to Year Ended December 31, 2005

Revenues.    Substantially all of our revenues are derived from the production of natural gas in the United States. Revenues were $26.8 million for the year ended December 31, 2006, down from $27.4 million for the year ended December 31, 2005. The decrease in revenues was the result of a 21% decrease in natural gas prices, which was partially offset by a 23% increase in production.

Natural Gas and Oil Production and Average Sales Prices.    Natural gas represents substantially all of our production. The table above sets forth production and sales information for the years ended December 31, 2006 and 2005.

Lease operating, transportation and selling expenses.    Lease operating, transportation and selling expenses were $8.6 million for the year ended December 31, 2006, up from $6.9 million for the year ended December 31, 2005. This increase was due to an increased number of producing wells. Our lease operating, transportation and selling expenses was $1.82 per Mcfe for the year ended December 31, 2006, compared to $1.81 for the comparable period in 2005.

Depreciation, depletion and amortization.    Depreciation, depletion and amortization was $16.3 million for the year ended December 31, 2006, up from $13.9 million for the year ended December 31, 2005. This increase primarily was attributable to new East Texas wells drilled and placed into production during 2006 and additional production from new CBM wells drilled in the Powder River Basin. The increase in DD&A expense was the result of a 23% increase in production, which was partially offset by an 5% decrease in the DD&A rate per unit of production. The DD&A rate for the year ended December 31, 2006 was $3.44 per Mcfe, as compared to $3.63 for the comparable period in 2005.

Impairment of natural gas and oil properties.    Impairment of natural gas and oil properties was $56.3 million for the year ended December 31, 2006, compared to $8.7 million for the comparable period ended 2005. The 2006 year impairment was the result of net natural gas and oil property costs, as adjusted for related deferred income taxes and other adjustments, exceeding the sum of estimated future net revenues using post end of period weighted average after basis adjustment prices held constant of $6.11 per Mcf for natural gas and $54.85 per barrel for oil, discounted at 10%, and United States unproven property at historical cost of $81.5 million, which was lower than the estimated fair market value, as adjusted for related income taxes and other adjustments. The

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2005 impairment is the result of net natural gas and oil property costs, as adjusted for related deferred income taxes, if any, and other adjustments, exceeding the sum of estimated future net revenues using prices in effect at June 30, 2005, the date of the impairment, held constant at $5.32 per Mcf for natural gas and $52.33 per barrel for oil, discounted at 10%, and unproven properties at historical costs of $93.3 million, which was lower than estimated fair market value, as adjusted for related deferred income taxes and other adjustments.

General and administrative.    We reported general and administrative expenses of $13.5 million for the year ended December 31, 2006, up from $8.7 million for the year ended December 31, 2005. This increase in general and administrative expenses was primarily due to increases in staff, contract personnel and professional service charges and the recording of non-cash compensation expense due to the granting of stock options. Stock-based compensation expense for 2006 pursuant to the SFAS 123(R), was $3.9 million, up from $2.3 million in 2005.

Litigation settlement expense.    The $2.4 million litigation settlement expense incurred in 2006 was primarily the result of a settlement payment regarding Western Gas Resources, Inc., et. al., of a lawsuit involving a gas gathering agreement and its applicability to properties we exchanged in 2002.

Interest expense.    We reported interest expense of $15.6 million for the year ended December 31, 2006, compared to $15.3 million for the year ended December 31, 2005. The increase in interest expense was the result of higher average debt outstanding and higher interest rates, which were partially offset by a decline in financing cost amortization. Interest expense includes deferred financing cost amortization of $4.3 million for 2006, a decrease of $500,000 from 2005.

Year Ended December 31, 2005 compared to Year Ended December 31, 2004

Revenues.    Substantially all of our revenues are derived from the production of natural gas in the United States. We reported revenues of $27.4 million for the year ended December 31, 2005, up from $6.1 million for the year ended December 31, 2004. This increase was attributable to the commencement of production of natural gas from our East Texas deep Bossier Field in late 2004 and continued 2005 field development and related production increases coupled with additional production from new CBM wells drilled in the Powder River Basin. The acquisition of additional leasehold and working interests in East Texas and the Powder River Basin from Geostar and higher prices for both natural gas and oil also contributed to the increase. Of the increase in revenues, 68% was attributed to higher production rates and 32% resulted from price increases.

Natural Gas and Oil Production and Average Sales Prices.    Natural gas represents substantially all of our production. The table above sets forth production and sales information for the years ended December 31, 2005 and 2004.

Lease operating, transportation and selling expenses.    Our lease operating, transportation and selling expenses were $6.9 million for the year ended December 31, 2005, up from $2.0 million for the year ended December 31, 2004. This increase was due to higher production volumes and an increased number of producing wells, which was partially offset by a reduction in severance and property taxes. Our lease operating, transportation and selling expenses per Mcfe were $1.81 during the year ended December 31, 2005, compared to $1.78 for the comparable period in 2004.

Depreciation, depletion and amortization.    Depreciation, depletion and amortization was $13.9 million for the year ended December 31, 2005, up from $3.2 million for the year ended December 31, 2004. This increase was attributable to the commencement of natural gas production from the wells in East Texas and the acquisition of additional leasehold and working interest properties in East Texas and the Powder River Basin from Geostar. Of the increase in DD&A expense, 73% was attributed to higher production rates and 27% was due to an increase in DD&A rate per unit. The DD&A rate for the year ended December 31, 2005 was $3.63 per Mcfe, as

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compared to prior comparable period of $2.89 per Mcfe. The increase in the DD&A rate is primarily due to higher capital expenditures in East Texas.

Impairment of natural gas and oil properties.    Impairment of natural gas and oil properties was $8.7 million for the year ended December 31, 2005, up from $6.3 million for 2004. The 2005 impairment is the result of net natural gas and oil property costs, as adjusted for related deferred income taxes and other adjustments, exceeding the sum of estimated future net revenues using prices in effect at June 30, 2005, the date of the impairment, held constant at $5.32 per Mcf for natural gas and $52.33 per barrel for oil, discounted at 10%, and unproven properties at historical costs of $93.3 million, which was lower than estimated fair market value, as adjusted for related deferred income taxes and other adjustments. The 2005 impairment was primarily the result of limited reserve additions during the current interim period and higher costs incurred to drill and complete the East Texas wells.

General and administrative.    General and administrative expenses were $8.7 million for the year ended December 31, 2005, up from $4.0 million for 2004. This increase in general and administrative expenses was primarily due to personnel increases, higher contract increases in staff, contract personnel and professional service charges, costs associated with our Form S-1 Registration Statement and non-cash compensation expense due to the issuance of stock options. Stock-based compensation expense for 2005 was $2.3 million, up from $1.4 million for 2004.

Interest expense.    Interest expense was $15.3 million for the year ended December 31, 2005, up from $3.2 million for the year ended December 31, 2004. This increase was due to higher debt outstanding as a result of the sale in 2004 of $3.25 million of subordinated unsecured notes payable, the sale in 2004 of $30.0 million of convertible senior debentures, the private placement in 2005 of $73.0 million of senior secured notes and the issuance in June 2005 of $32.0 million in unsecured subordinated notes to Geostar. Interest expense includes deferred financing cost and debt discount amortization of $4.8 million for 2005, an increase of $4.0 million from 2004. In addition in June 2005, the senior unsecured notes were paid in full and a call premium of $622,000 was paid.

Liquidity and Capital Resources

At December 31, 2006, we had cash and cash equivalents of $40.7 million and the ability to issue up to $10.0 million of additional senior secured notes. For the year ended December 31, 2006, we reported negative cash flow from operations of $1.3 million. Capital expenditures on natural gas and oil properties during 2006 totaled $55.7 million during the period.

Pursuant to the terms of our senior secured notes, we have the right, exercisable quarterly to June 16, 2007, to require the original purchasers of the senior secured notes to purchase additional notes in an amount limited to an aggregate of $10.0 million in principal, provided that we comply with proved plus probable reserve present value discounted at 10%, or PV(10), to net senior secured debt coverage ratio of 2.5:1 and proved reserve PV10 to net senior secured debt coverage ratio of 1.0:1 and other general covenants and conditions. The PV(10) value is to be based on a third party independent reserve report utilizing constant pricing based on the lower of current natural gas and oil prices or $6.00 per Mcf of natural gas and $40.00 per barrel of oil.

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, non-strategic asset sales, the issuance of additional senior secured notes, the issuance of subordinated notes or the issuance of

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additional equity. We may also attempt to balance future capital expenditures through joint venture development of certain properties with industry partners. We are in the early stages of exploration and development of our East Texas properties. Amounts and timing of future cash flows is dependent on confirmation of production from recently completed wells, together with the success of currently drilling and future wells to be drilled. We cannot be certain that future funds will be available to fully execute our current business plan.

Our capital expenditures in the next twelve months under our current business plan are estimated to total approximately $75.8 million, of which $54.5 million is estimated to be spent on our deep Bossier natural gas exploration and development operations, $3.8 million is estimated to be spent on CBM projects in the United States and $17.5 million is estimated to be spent on CBM projects in Australia. Given the forecast for natural gas and oil prices, cash on hand and projected production volume increases, we believe that approximately $50 million of additional financing will be necessary to execute our business and operational plans over the next twelve months. The additional financing funds will most likely include internally generated cash flow, cash on hand, non-strategic asset sales, the issuance of additional senior secured notes, the issuance of subordinated notes or the issuance of additional equity. If we can not obtain these funds in capital market transactions, loans or otherwise, we may have to revise our business plan and reduce our capital drilling program.

On November 17, 2006, the Company closed a private placement of 25,000,000 of its common shares at $2.00 per share. The shares were sold to institutional accredited investors in the United States, including Chesapeake. Net proceeds from this placement of $47.8 million, after deducting placement fees and estimated expenses, is being used to fund the Company’s drilling programs and for general corporate purposes.

We 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.

We currently have no natural gas price financial instruments or hedges in place. Our natural gas marketing contracts use “spot” market prices. We may enter into long-term fixed-price natural gas contracts, swap or hedge positions, other gas financial instruments or financial derivatives later in 2007. A senior secured notes covenant restricts us from hedging more than 50% of future production.

At December 31, 2006, we were in compliance with all debt covenants.

Off Balance Sheet Arrangements

As of December 31, 2006, we had no off balance sheet arrangements. We have no plans to enter into any off balance sheet arrangements in the foreseeable future.

Contractual Obligations

The following table summarizes our future contractual obligations under these arrangements as of December 31, 2006:

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We maintain a reserve for cost associated with the retirement of tangible long-lived assets. At December 31, 2006, our reserve for these obligations totaled $4.2 million for which no contractual commitment exists. Information about this reserve is set forth in Footnote 9 “Asset Retirement Obligation” to our consolidated financial statements, which begins on page F-1.

We have employment contracts with our Chief Executive Officer and Chief Financial Officer, which obligate us to pay a specified level of salary, target bonus and certain other payments and reimbursements to them during their employment and in the event of termination or change of control. Information about such payments is set forth in Item 11, “Executive Compensation”.

Commitments

In February 2007, we entered into a letter agreement with ETC Texas Pipeline, Ltd. that expands our existing transportation and treating agreement to meet the future gathering, treating and transportation of natural gas produced and owned or controlled by us in the Hilltop area of East Texas. Under the letter agreement, ETC would construct a gathering system sufficient to gather and treat up to 150 MMcfd, and we would deliver to ETC a minimum of approximately 135 Bcf over a 10-year period. Minimum annual sales over the 10-year period and fees for the gathering and treating of natural gas are currently being negotiated.

In March 2007, we and our Australian joint venture partner in PEL 238 agreed to acquire outstanding overriding royalty interests from several outside parties including directors of the joint venture partner. The terms of the agreements call for us to acquire and terminate our 35% share of a 4% overriding royalty interest in PEL 238 at a net cash price of $2.5 million payable May 3, 2007. In addition, we are to reimburse our joint venture partner in cash for our 35% share of overriding royalty interests acquired and terminated by the joint venture partner using the joint venture partner’s common stock as compensation. We expect our share of the costs associated with the acquisition and termination of overriding royalty interests acquired to be approximately $2.9 million due on or before May 2, 2007 or within three days of notice from the joint venture partner if the shares are issued after May 2, 2007.

Future Share Issuances

Pursuant to the Geostar Acquisition, Geostar may receive additional common shares based on look-backs at June 30, 2006 and June 30, 2007 on the East Texas assets, based on a required number of drilled wells, and net reserve additions valued at $1.50 per Mcf less attributable development expenditures to Geostar’s acquired interest. The look-back calculations are to be based on a third party engineering report and calculated within 60 days of receipt of the engineering report. Common shares to be issued, if any, are to be based on the five day weighted average trading price on the day preceding the actual payment of shares, discounted by ten percent. Based on our look-back analysis at June 30, 2006, no additional shares are due to Geostar at this time. We are still awaiting confirmation of Geostar’s June 30, 2006 look-back review results.

As of the date of this filing, Geostar has neither responded to the June 30, 2006 look-back analysis that we provided nor provided us an independent reserve analysis disputing our June 30, 2006 look-back analysis, which, as called for in the Purchase and Sale Agreement, would be averaged with our independent reserve analysis for the purpose of determining how many, if any, shares would be due to Geostar.

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Common Share Registration Obligation and Penalties

On November 17, 2006 (“Closing Date”), we issued to various subscribers 25 million of our common shares for $50.0 million (“Aggregate Subscription Price”). We have agreed to use our reasonable commercial efforts to file a registration statement covering the resale of the common shares within 120 days of the Closing Date (the “Filing Deadline”) and to cause the registration statement to be declared effective within 180 days of the Closing Date (the “Effectiveness Deadline”). We agreed to cause the registration statement to remain effective until the earlier of (i) 30 days after all the common shares have been sold under the registration statement, or (ii) one year from the Closing Date (the “Effectiveness Period”). If the registration statement is not filed by the Filing Deadline, we agreed to pay to the subscribers an amount in cash equal to 1.5% of the Aggregate Subscription Price per month for the period between the Filing Deadline and the date that the registration statement is filed. If the registration statement is not declared effective by the Effectiveness Deadline or shall cease to be effective for any period of time during the Effectiveness Period, we agreed to pay to the subscriber an amount in cash equal to 1.5% of the Aggregate Subscription Price per month until such time as the registration statement is declared effective or the common shares become freely tradable pursuant to Rule 144(k), generally two years. Such amounts will accrue daily and be paid monthly in arrears. The total penalty fee payable to the subscribers is limited to aggregate payments of 8% of the Aggregate Subscription Price or $4.0 million. We filed an S-3 Registration Statement on February 2, 2007 in regards to the common shares and are waiting for such to be declared effective once our Annual Report on Form 10-K is filed.

New Accounting Pronouncements

Accounting for Certain Hybrid Financial Instruments

In February 2006, the Financial Accounting Standards Board, or FASB, issued SFAS No. 155, “Accounting for Certain Hybrid Instruments—an amendment of SFAS Statements 133 and 140”, which is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The statement improves financial reporting by eliminating the exemption from applying SFAS No. 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments. The statement also improves financial reporting by allowing a preparer to elect fair value measurement at acquisition, at issuance, or when a previously recognized financial instrument is subject to a re-measurement event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated, if the holder elects to account for the whole instrument on a fair value basis. The adoption of this statement is not expected to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.

Accounting for Uncertainty in Income Taxes

In June 2006, the FASB issued SFAS No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of SFAS 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 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding derecognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. The adoption of this Interpretation is not expected to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.

Guidance for Quantifying Financial Statement Misstatement

In September 2006, the SEC issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”), which establishes an approach requiring the quantification of financial statement errors based on the effect of the error on each of the company’s financial statements and the related financial statement disclosures. This model is

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commonly referred to as a “dual approach” because it requires quantification of errors under both the “iron curtain” and “roll-over” methods. The roll-over method focuses primarily on the impact of a misstatement on the income statement, including the reversing effect of prior year misstatements; however, its use can lead to the accumulation of misstatements in the balance sheet. The iron curtain method focuses primarily on the effect of correcting the period end balance sheet with less emphasis on the reversing effects of prior year errors on the income statement. The Company currently uses the iron curtain method for quantifying financial statement misstatements. The Company will initially apply the provisions of SAB 108 in connection with the preparation of the Company’s annual financial statements for the year ending December 31, 2006. The use of the dual approach did not have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.

Fair Value Measurements

In September 2006, the 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 does not expect the adoption of SFAS No. 157 to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.

Commodity Price 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 year ended December 31, 2006, a 10% change in the prices received for natural gas production would have had an approximate $2.7 million impact on our revenues. To date, we have not entered into hedge transactions to mitigate our commodity pricing risk.

Interest Rate Risk

The carrying value of our debt approximates fair value. At December 31, 2006, we had approximately $106.3 million in principal amount of long-term debt of which $73.0 million of the senior secured notes was subject to a floating interest rate of LIBOR plus 6%. A 10% fluctuation in interest rates would have an approximate $391,000 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. In 2006, our Australian activities consisted of capital expenditures totaling approximately $4.6 million. We have no plans in the foreseeable future to implement hedges or financial instruments to manage international currency changes.

The reports of our independent registered public accounting firms and our consolidated financial statements and supplementary information are presented beginning on Page F-1 of this Form 10-K.

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None

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 December 31, 2006 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 December 31, 2006, that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

None.

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PART III

Directors, Executive Officers and Certain Other Officers

Our directors, executive officers, who are also referred to as “named executive officers”, and certain other significant employees and their ages as of March 20, 2007 are as follows:

J. Russell Porter has been a member of our Board of Directors and has served as our Chief Executive Officer and President since February 2004. From September 2000 to February 2004, he served as our Chief Operating Officer. Mr. Porter has an energy focused background, with approximately 16 years of natural gas and oil exploration and production experience and five years of banking and investment experience specializing in the natural gas and oil industry. From April 1994 to September 2000, Mr. Porter served as an Executive Vice President of Forcenergy, Inc., a publicly traded exploration and production company, where he was responsible for the acquisition and financing of the majority of its assets across the United States and Australia. He currently is a director of Caza Oil & Gas Company, a privately held exploration and development company. Mr. Porter holds a bachelor of science degree in Petroleum Land Management from Louisiana State University and a MBA from the Kenan-Flagler School of Business at the University of North Carolina at Chapel Hill.

Michael A. Gerlich joined Gastar in May 2005, as Vice President and Chief Financial Officer. From 1994 until joining Gastar, Mr. Gerlich served as Senior Vice President – Accounting and Finance for Calpine Natural Gas L.P., formerly known as Sheridan Energy, Inc., where he served as Vice President and Chief Financial Officer. Over a 10 year period prior to joining Sheridan Energy, Mr. Gerlich held various accounting and finance positions with Trinity Resources, Ltd., with his last position being Executive Vice President and Chief Financial Officer. Mr. Gerlich was also with a Big Four accounting firm, where the focus of his practice was with energy related clients. Mr. Gerlich is a Certified Public Accountant and graduated with honors from Texas A&M University with a bachelor degree in accounting.

Frederick E. Beck, PhD joined Gastar in April 2002, as Vice President of Drilling. Dr. Beck has over 25 years of diversified experience in the oil and gas business. He has held positions with a major operator as a drilling engineer and drilling supervisor and as an assistant professor of petroleum engineering at the New Mexico School of Mines. From 1996 and prior to joining Gastar as Vice President of Operations, Dr. Beck was Vice President of the turnkey drilling division of Nabors Drilling USA LP. Dr. Beck holds a B.S. degree in Geology, Master of Science degree in Petroleum Engineering and Doctor of Philosophy Degree in Petroleum Engineering, all from Louisiana State University in Baton Rouge, Louisiana.

R. David Rhodes joined Gastar in March 2006, as Vice President of Completion and Production. Mr. Rhodes has over 25 years of petroleum engineering experience, focused primarily in the supervision and management of completion and production operations. Prior to joining Gastar, he managed Oil & Gas Operations

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and Consulting, Inc., an independent consulting firm he established in May, 2001. There, he worked as a petroleum engineering consultant for numerous natural gas and oil operators including Gastar. From 1984 to 2001, Mr. Rhodes held various engineering and management/supervisory positions at Marathon Oil Company (formerly Texas Oil & Gas Company). His last position was Operations Manager for East Texas and Northern Louisiana. Mr. Rhodes holds a Bachelor of Science degree in Petroleum Engineering from Louisiana Tech University.

Henry J. Hansen joined Gastar in September 2005, as Vice President of Land. Prior to joining Gastar, Mr. Hansen was Rocky Mountain Land Manager with El Paso Corporation from 1999 until January, 2003. He returned to El Paso Corporation in June of 2004, where he was senior landman until joining Gastar in September 2005. Mr. Hansen graduated from the University of Texas at Austin, Texas with a Bachelor of Business Administration.

Sara-Lane Sirey, LLB is an attorney in private practice, who has served as the Corporate Secretary of Gastar and General Corporate Canadian Counsel since May 2000. From July 1993 to April 2001, she served as an attorney at the law firm of Armstrong Perkins Hudson LLP (formerly Ogilvie and Company) in Calgary, Alberta, Canada, becoming a partner in 1999. Focusing on corporate/securities law, she has acted for issuers, in all industry segments, in Canada, the United States and internationally, focusing on corporate reorganizations, commercial transactions and initial public offerings of junior emerging companies as well as equity and debt financings, mergers and acquisitions and commercial transactions of senior established companies. Ms. Sirey obtained her Bachelor of Laws degree at the University of Saskatchewan.

Abby F. Badwi has been a member of our Board of Directors since February 2004. Mr. Badwi is an international energy executive with more than 30 years of experience in the exploration, development and production of natural gas and oil fields in North America, South America, Asia and the Middle East. He has been President and CEO of Rally Energy Corp., a natural gas and oil company publicly traded on the Toronto Stock Exchange with operations in Egypt, Pakistan and Canada, since July 2005. Prior to joining Rally Energy, he was the President of Corrundum Energy Ltd, a private natural gas and oil investment and advisory firm from 2003 until 2005. From 2000 until 2003, he was President and CEO of Geodyne Energy Inc., a natural gas and oil venture publicly traded on the Toronto Stock Exchange. Mr. Badwi has been an officer of several Canadian public and private companies, including President and COO of Carmanah Resources Ltd., a Calgary, Alberta-based company with oil holdings in Canada, Indonesia and Venezuela, and Vice President International Exploration of Sceptre Resources Limited, an oil and gas exploration and production company. He is currently a director of Rally Energy Corp., Arpetrol Inc., Sustainable Energy Technologies Ltd., and Fairmount Energy Inc. Mr. Badwi holds a Bachelor of Science degree in petroleum geology from the University of Alexandria, Egypt.

Thomas L. Crow has been a member of our Board of Directors since April 2002. Mr. Crow was the founder and President of Cobra Golf Inc. (a worldwide leading manufacturer of golf clubs which was listed on NASDAQ) from 1973 to 1994 and served as Vice President from 1994 to 1996 when Cobra Golf Inc. was acquired to be a subsidiary of Fortune Brand Inc. (a significant NYSE conglomerate). From 1997 to 2002, Mr. Crow remained as Chairman Emeritus of Cobra Golf Inc. Since 2002, Mr. Crow has been an independent businessman.

Richard A. Kapuscinski has been a member of our Board of Directors since July 2000. Since 1999, Mr. Kapuscinski is Director of Marketing at Turbo Power Systems Inc., responsible for North American business development. Turbo Genset is a designer and manufacturer of products for power generation and power conditioning. From 1986 to 1999, he worked as a Sales Marketing Manager with Tyco International (US) Inc. (formerly Keystone Valve). Mr. Kapuscinski is a Certified Mechanical Engineering Technologist and is a member of the Ontario Association of Certified Engineering Technicians and Technologists and the Instrument Society of America. He studied Mechanical Engineering at Lambton College in Sarnia, Ontario, Canada concentrating on the petroleum and petrochemical industry.

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Of our directors, Messrs. Crow and Porter are citizens of the United States, while Messrs. Badwi and Kapuscinski are citizens of Canada. There are no family relationships between any of our directors or executive officers.

Section 16 Reporting

Section 16(a) of the Exchange Act requires the Company’s directors and officers and persons who own more than 10% of a registered class of the Company’s equity securities to file reports of ownership and changes in ownership with the SEC. Directors, officers, and greater-than-10% stockholders are required by SEC regulations to furnish the Company with copies of all Section 16(a) forms they file. Based solely on review of information furnished to the Company, the Company believes that all Section 16(a) filing requirements applicable to its directors, officers, and greater than 10% beneficial owners were complied with during the year ended December 31, 2006.

Code of Ethics

We adopted a Code of Ethics for senior management including our principal executive officer and principal financial officer on December 15, 2005. A copy of our Code of Ethics was filed as an exhibit to our Registration Statement on Form S-1/A on December 22, 2005 and is also available on our internet website at www.gastar.com. A copy of our Code of Ethics will be provided to any person without charge, upon request. Such requests should be directed to J. Russell Porter, President and Chief Executive Officer, 1331 Lamar Street, Suite 1080, Houston, Texas 77010.

Shareholders or other interested parties may send communications to the Board of Directors by writing through the Secretary of the Company at 1331 Lamar Street, Suite 1080, Houston, Texas 77010. The Secretary will forward to the directors all communications that, in his or her judgment, are appropriate for consideration by the directors. Comments or complaints relating to our accounting, internal accounting controls or auditing matters will also be referred to members of the Audit Committee. The Audit Committee has procedures for (a) receipt, retention and treatment of complaints received by us regarding accounting, internal accounting controls, or auditing matters and (b) the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters.

Audit Committee

The Audit Committee currently is comprised of Messrs. Badwi (Chairman and financial expert) and Crow. After reviewing the qualifications of the current members of the Audit Committee, the Board of Directors has determined that all current Audit Committee members are “independent”, as that concept is defined in Section 10A of the Exchange Act, and the applicable rules of the American Stock Exchange. The Board of Directors also determined that all current Audit Committee members are financially literate and that Mr. Badwi is a “financial expert” under the applicable rules of the Exchange Act. In accordance with its Terms of Reference, the Audit Committee examines and reviews on behalf of the Board of Directors, internal financial controls, financial and accounting policies and practices, related party transactions and the form and content of financial reports and statements. The Audit Committee is responsible for the hiring, overseeing and terminating the independent accountants engaged to prepare any audit or issue any audit report, and the work of the external auditors. The Chief Financial Officer attends the meetings of the Audit Committee by invitation.

On March 15, 2007, we notified the American Stock Exchange that we were not in compliance with the American Stock Exchange Company Guide Rule 121(B)(2)(a), which requires that each listed company must have, and certify that it has and will continue to have, an audit committee of at least three independent members. As a result of an independent member of our Audit Committee not standing for reelection at our 2006 annual meeting of shareholders, the Audit Committee was left with two independent members, one of whom remains designated as its “financial expert”.

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Notwithstanding our current non-compliance with the American Stock Exchange rule regarding the number of independent directors serving on the Audit Committee, at all times since January 4 2006, the date we first became listed and subject to the reporting requirements of the Exchange Act, as amended, our Audit Committee has consisted solely of directors meeting the independence requirements of the American Stock Exchange and Section 10A of the Exchange Act.

We intend to rectify this non-compliance as soon as practicable. We have instituted a search and expect to appoint a new director meeting the independence requirements to fill the vacancy on the Audit Committee prior to our annual meeting of shareholders expected to be held in June 2007. As of the date of this report, we have not received any warning notice or notice of deficiency from the American Stock Exchange regarding this non-compliance.

Compensation Discussion and Analysis

The following Compensation Discussion and Analysis explains our compensation objectives, philosophy and practices with respect to our chief executive officer and chief financial officer, who are referred to as Named Executive Officers. These individuals are our only executive officers.

Remuneration Committee

Executive compensation is the responsibility of the Remuneration Committee. The Remuneration Committee operates under a written charter, or the “Terms of Reference”, adopted by the Board of Directors. Abby F. Badwi, Thomas L. Crow and Richard A. Kapuscinski are members of the Board of Directors and members of the Remuneration Committee. Mr. Badwi is the Remuneration Committee Chairman. Each member of the Remuneration Committee qualifies as an independent director under the American Stock Exchange listing standards and under the Exchange Act.

Compensation Consultants

The Remuneration Committee does not generally engage a compensation consultant to provide advice with respect to the amount or form of executive and director compensation.

Role of Named Executive Officers in Establishing Compensation

The compensation of our Chief Executive Officer is determined by the Remuneration Committee. In determining the compensation of the Chief Executive Officer, the Remuneration Committee takes into account the Chief Executive Officer’s responsibilities and performance, the Company’s performance and the market in which the Company competes for executive talent. The Chief Executive Officer does not attend any meetings related to his compensation. The compensation of our Chief Financial Officer is determined by the Remuneration Committee, after receiving the recommendations of the Chief Executive Officer. The recommendations are based on an assessment of the Chief Financial Officer’s responsibilities and performance, the Company’s performance and the market in which the Company competes for executive talent. The Chief Executive Officer attends those portions of the meetings of the Remuneration Committee that are related to the Chief Financial Officer’s compensation.

Compensation Philosophy

Our compensation programs for Named Executive Officers are designed to achieve the following objectives:

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Benchmarking of Compensation

We believe that the compensation of the Named Executive Officers should be competitive with the market in which we compete for executive talent. We gather information about this market by reviewing publicly available information about our competitors and by having discussions with individuals knowledgeable in recruiting executives in the natural gas and oil industry.

Elements of Executive Compensation and Rationale

There are three key elements to our compensation: base salary, annual cash bonus awards and stock-based compensation. We believe that a combination of these three elements balances rewards for current performance and longer term corporate objectives as measured, among other things, by stock performance. The terms of the Named Executive Officers’ employment, including their compensation and other benefits, are set forth in employment contracts, described below.

The Company entered into employment agreements with J. Russell Porter, our President and Chief Executive Officer, and Michael A. Gerlich, our Chief Financial Officer, effective February 24, 2005 and May 17, 2005, respectively. Each agreement renews annually unless terminated in accordance with the provisions of the agreement. Each year the Remuneration Committee determines base salary, bonus and equity awards under each employment agreement, subject to certain provisions of the agreement.

Base Salary.    Base pay represents the fixed element of the Named Executive Officer’s cash compensation. The base pay reflects the individual’s responsibilities, performance, skill set and the market value of that skill set. Base salaries for our Named Executive Officers are set at the beginning of each employment contract anniversary year.

Pursuant to the terms of Mr. Porter’s employment agreement, his base salary is initially set at $450,000 but may be adjusted upward or downward at each year’s anniversary date at the discretion of the Remuneration Committee, except that in the event that the Remuneration Committee should determine to decrease Mr. Porter’s base salary, Mr. Porter has the right to be advised of the basis for this decision and an opportunity to discuss the decision with the Remuneration Committee. In 2006, the Remuneration Committee made no changes to Mr. Porter’s base salary, based on its determination that the existing base salary was competitive and appropriate in light of the overall level of corporate activity. Mr. Gerlich’s annual compensation is set at $275,000 but may be adjusted upward, or downward, at each year’s anniversary date at the discretion of the Remuneration Committee, except that in the case of a downward adjustment, such decrease can generally not be greater than ten percent (10%) per year and no more than twenty percent (20%) in total of his original salary, unless the salary of the Chief Executive Officer has been reduced in certain specified amounts as well. In 2006, the Remuneration Committee made no changes to Mr. Gerlich’s base salary, based on its determination that the existing salary was competitive and appropriate in light of Mr. Gerlich’s tenure with the Company and the overall level of corporate activity.

Annual Cash Bonus Awards.    Our cash bonus awards provide our Named Executive Officers, as well as other employees, an opportunity to earn an annual cash bonus that is based on an evaluation of individual performance and the performance of the Company. Annual cash bonuses are determined for our Named Executive Officers by the Remuneration Committee. In the case of the bonus for the Chief Financial Officer, the Chief Executive Officer makes a recommendation to the Remuneration Committee with respect to the cash

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bonus. Subject to the terms of the employment agreements relating to the Named Executive Officers, as described below, determinations relating to the amount of the cash bonus are based on an evaluation of the Company’s performance over the past year, the Named Executive Officer’s performance and the contributions of the Named Executive Officer to the Company’s performance. Annual cash bonus awards for our Named Executive Officers are determined at the end of each calendar year. Additional cash bonuses may be awarded to our Named Executive Officers during the year, as determined in the discretion of the Remuneration Committee. Other than annual cash bonuses paid in 2006, no other cash bonuses were paid in 2006.

Mr. Porter’s employment contract provides that he is entitled to an annual bonus in an amount which may take the form of cash compensation, the award of stock or stock options, royalty rights or otherwise and that he shall receive an annual cash bonus equal to at least 20% of his annual base salary. The employment agreement further provides that the bonuses shall reflect not only the results of the Company’s operations and business, but his contribution as President and Chief Executive Officer. For 2006, Mr. Porter was paid a cash bonus of $225,000, or 50% of his base salary. His bonus for 2006 reflected the Remuneration Committee’s positive evaluation of Mr. Porter’s leadership during a year that we became a reporting company under United States’ securities law, listed on the American Stock Exchange, as well as his success in completing the sale of a significant ownership position in the Company to an industry partner and in raising significant equity capital to finance our expanded exploration activities in East Texas and Australia. No stock awards (other than stock option grants) or royalty awards were made to Mr. Porter in 2006.

Mr. Gerlich’s employment contract provides that his first year bonus shall equal at least 20% of his gross salary. In future years, the Remuneration Committee may (but is not obligated) on a yearly basis, or at such more frequent times as it may elect, award Mr. Gerlich a discretionary bonus or bonuses. Such bonuses may take the form of cash compensation, the award of stock or stock options, royalty rights or otherwise. A bonus reflects not only the results of our operations and business, but of Mr. Gerlich’s contribution to our operations and business. For 2006, Mr. Gerlich was paid a cash bonus of $96,000, or 35% of his base salary. His bonus reflected Mr. Porter’s and the Remuneration Committee’s positive evaluation of Mr. Gerlich’s leadership in establishing an autonomous Houston-based accounting and financial department, in transitioning us from a Canadian reporting company to a United States reporting company listed on the American Stock Exchange, and his contributions in completing the sale of a significant ownership position to an industry partner, and in raising significant equity capital to finance our expanded exploration activities in East Texas and Australia. No stock awards (other than stock option grants) or royalty awards were made to Mr. Gerlich in 2006.

Stock-based Compensation.    We believe that equity compensation is the most effective means of linking compensation provided to our Named Executive Officers with increases in shareholders’ value. Historically, we have used stock options as the equity compensation vehicle. Stock options are generally granted to new hires at the time of employment and to all others, including our Named Executive Officers, around the time of our annual meeting of shareholders. Additional stock options may be granted during the year upon accomplishment of certain corporate goals or as an incentive tool. The Board of Directors has discretionary authority to determine vesting periods of stock options. Typically, vesting periods are over a four year period beginning with 25% of the award vesting on the first anniversary of the date of the grant and an additional 25% vesting on each of the next three anniversary dates. However, recent stock option grants to our Chief Executive Officer and certain technical managers vest over two years. Other stock options granted on the same date to the Chief Financial Officer and other employees vest over three years. The stock option awards having shorter vesting periods were granted to provide additional shorter term incentive to our Named Executive Officers, certain technical and other employees. All stock options incorporate the following features:

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We continue to use stock options as a long-term incentive vehicle because we believe:

Pursuant to our stock option plans, the Board of Directors has designated the Remuneration Committee as the committee to administer the granting of stock options. Stock option grants are determined by the Remuneration Committee, based on the recommendations of our Chief Executive Officer, except in the case of stock option grants awarded to the Chief Executive Officer. In determining the number of stock options to be granted to Named Executive Officers, as well as other employees, the Remuneration Committee takes into account the Named Executive Officer’s position, the scope of his responsibilities, his ability to affect profits and shareholder value and the individual’s past and recent performance.

In 2006, Mr. Porter was granted stock options to acquire an aggregate of 1,150,000 of our common shares, of which 150,000 stock options vest over four years and 1,000,000 stock options vest over two years. In the event of Mr. Porter’s termination, with or without cause, all unvested options will vest and be exercisable for a period of 90 days from the date of termination. The 150,000 share grant dated April 5, 2006 was a part of a larger grant of stock options to employees designed to motivate and provide additional employee incentives. The 1,000,000 share grant dated July 14, 2006 was in recognition of Mr. Porter’s leadership during a transition year, the completion of the sale of a significant ownership position in us to an industry partner and his success during the year in raising significant equity capital to finance our expanded exploration activities in East Texas and Australia.

In 2006, Mr. Gerlich received three grants to acquire a total of 650,000 common shares. Of the 250,000 share grant dated January 16, 2006, 125,000 stock options were granted pursuant to his employment agreement and 125,000 stock options were granted in recognition of our successful transition from a Canadian reporting company to a United States reporting company listed on the American Stock Exchange. The 100,000 share grant dated April 5, 2006 was a part of the larger grant of stock option to employees described above. The 300,000 share grant dated July 14, 2006 was in recognition of Mr. Gerlich’s successful establishment of an autonomous Houston-based accounting and financial department, his role in our transition to a United States reporting company and his contributions to our capital raising program.

Perquisites.    The Named Executive Officers are eligible to participate in the same comprehensive benefits as are offered to all full-time employees. Mr. Porter’s employment agreement provides that we will pay or reimburse Mr. Porter up to $25,000 for his membership dues in such clubs and/or organizations as are reasonable and customary for a senior executive officer and will reimburse him for the cost of a yearly executive physical examination and all required or recommended medical testing in connection with that yearly examination.

We paid, or reimbursed, Mr. Porter a total of $95,892 during 2006. Of this amount, $19,962 related to the rental and related utility costs for an apartment in Houston, Texas; $41,264 related to the rental of an office in Miami, Florida (our Chief Executive Officer’s city of residence); and $13,274 related to the use of a rental car while in Houston. The balance of $21,392 was related to airfare between Houston and Miami, club dues, an executive health physical examination and the Company’s contribution to Mr. Porter’s 401-K plan. Each of the items was incurred by or on behalf of Mr. Porter in the ordinary course of business or for his convenience and was considered reasonable and customary perquisites for a senior executive officer.

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Other than the comprehensive benefits offered to all full-time employees, Mr. Gerlich did not receive any perquisites having a value over $10,000 in aggregate during 2006.

Post Termination or Change of Control Compensation and Benefits

Mr. Porter’s employment agreement provides that his employment shall terminate (i) without notice upon his death; (ii) without notice upon his “Disability”, as defined in his employment contract; (iii) upon six month’s written notice to the Company by Mr. Porter for any or no reason, with or without cause; (iv) upon one year’s written notice to Mr. Porter by the Company for any or no reason, with or without cause; or (v) by the Company without prior notice upon a showing of “Reasonable Cause” (as defined in his employment contract).

Mr. Gerlich’s employment agreement provides that his employment shall terminate (i) without notice, upon his death; (ii) without notice, upon his “Disability”, as defined in his employment contract; (iii) upon two month’s written notice to the Company by Mr. Gerlich for any or no reason, with or without cause; (iv) if there is a “change of control”, as defined in his employment contract and that “change in control” results in a material change in the scope of Mr. Gerlich’s duties and responsibilities such that he terminates his employment; (v) upon two month’s written notice to Mr. Gerlich by the Company for any or no reason, with or without cause; (vi) or by the Company without prior notice, upon a showing of “Reasonable Cause” (as defined in his employment contract).

Pursuant to the terms of their respective employment agreements, Messrs. Porter and Gerlich are entitled to receive certain post termination compensation and benefits. These benefits were determined in the negotiations with each individual and were based on what the Board of Directors determined were elements of a competitive compensation arrangement at the time. See “Potential Payments upon Termination or Change of Control” below.

On March 23, 2007, our Board of Directors approved a change of control severance plan covering all employees, including the Named Executive Officers. The purpose of the severance plan is to promote stability and continuity of management and regular employees in the event a change of control transaction should occur. A change of control is defined in the severance plan to mean (1) the consummation of a merger, consolidation, reorganization or other transaction whereby our shareholders retain less than 50% control, directly or indirectly, of us or the surviving company, (2) our incumbent directors cease to constitute a majority of the board of directors or (3) a sale or other disposition of all or substantially all of our assets. The severance plan does not change the specific, non-change of control severance payments in place under the existing employment contracts with our Named Executive Officers but does provide change of control severance benefits to the Named Executive Officers only if they are greater than the severance benefits provided under the employment agreement. The change of control severance plan does not allow for any duplication of severance benefits.

For the Named Executive Officers, the severance plan provides that if a Named Executive Officer’s employment is terminated within two years following a change of control for any reason other than (i) death, (ii) disability, (iii) by us for “cause”, or (iv) by the Named Executive Officer for other than a “good reason”, the Named Executive Officer will receive a lump-sum payment equal to a multiple that is equal to the applicable severance period, as set forth in the change of control severance plan, times the sum of (1) his annual salary and (2) annual target bonus.

The following summarizes the severance periods and target bonus percentages for the Named Executive Officers:

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Additionally, during the applicable severance period, Named Executive Officers would receive reimbursement for the cost of COBRA continuation health care coverage, less the amount charged at the time of termination to the employee for their medical coverage.

If the Named Executive Officer receives a payment or benefit that is subject to the “golden parachute” excise tax, the Named Executive Officer will receive an additional payment under the severance plan to make him or her “whole” for that excise tax and any taxes on the additional parachute tax gross-up payment.

If the individual’s employment is terminated within six months prior to a change of control and it is reasonably shown to have been in connection with the change of control, then the change of control will be treated, with respect to that employee, as having occurred prior to his or her termination.

REMUNERATION COMMITTEE REPORT

Board of Directors of Gastar Exploration Ltd.

The Remuneration Committee has reviewed and discussed the Compensation Discussion and Analysis with management; and based on the review and discussions referred to above, the Remuneration Committee recommends to the Board of Directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the year ended December 31, 2006 and in the Company’s proxy statement on Schedule 14A.

GASTAR EXPLORATION LTD.

REMUNERATION COMMITTEE

The above Report of the Remuneration Committee of the Board of Directors does not constitute soliciting material and should not be deemed filed or incorporated by reference into any other Company filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent the Company specifically incorporates this Report by reference therein.

Summary Compensation and Awards

The following table and discussion below sets forth information about the compensation awarded to, earned by or paid to our Named Executive Officers during the year ended December 31, 2006.

Summary Compensation Table