Overview

We are a Houston, Texas-based independent natural gas and oil company engaged in the exploration, development and production of natural gas and oil in the United States and Australia. Our domestic drilling activities are focused on exploiting our multi-year inventory of drilling locations in the deep Bossier sands and Knowles Limestone plays in the Hilltop area of East Texas and continuing exploitation of our coal bed methane, or “CBM”, assets in the Powder River Basin of Wyoming and Montana. Our operations in Australia are focused on the development of over 7.0 million gross (2.9 million net) acres of CBM rights in New South Wales and Victoria, Australia. We believe that our dual focus enables us to generate high initial production and long-lived producing wells with strong cash flow dynamics from our East Texas activities, while also providing us with significant reserve upside through the development of our Australian resource plays. We are a Canadian corporation incorporated in Alberta in 1987. We are publicly traded on the American Stock Exchange under the ticker symbol “GST” and on the Toronto Stock Exchange, or TSX, under the ticker symbol “YGA”.

Our Strategy

Continue Exploitation of Existing East Texas Assets.     Our East Texas portfolio includes 18 producing wells, which we anticipate will grow to 25 wells over the next 12 months. We have identified numerous Bossier and Knowles Limestone potential drilling opportunities on our current acreage position. These assets represent opportunities with strong return characteristics supportive of significant near-term production and cash flow growth.

Actively Manage Our Domestic Drilling Program.     We believe operating our core East Texas properties enables us to control the timing and cost of our drilling budget, as well as control operating costs and the marketing of our production. We have assembled an experienced team of operating professionals with specialized skills necessary to plan and execute the drilling and completion of the deep, high-temperature and high-pressure wells targeting the deep Bossier formation.

Exploit CBM Asset Base.     Our asset positions in southeastern Australia represent opportunities for significant reserve growth through our CBM drilling programs. Due to our pilot production success and the anticipated build up in the energy infrastructure in New South Wales, we anticipate continued participation with our operating partners in further pilot production, core-hole and other exploratory CBM activities. Initial commercial production from the Petroleum Exploration License “PEL” No. 238, or “PEL 238”, is anticipated in late 2008. We continue to evaluate our other CBM assets in the Powder River Basin in Wyoming and Montana for continued development drilling and re-completion activities that provide a source of stable production and cash flow.

Manage and Utilize Technological Expertise.     We believe that 3-D seismic analysis, enhanced natural gas recovery processes, horizontal drilling, and other advanced drilling technologies and production techniques are useful tools that improve drilling results and ultimately enhance production and returns. We believe that utilizing these technologies and production techniques in exploring for, developing and exploiting natural gas and oil properties will help us reduce drilling risks, lower finding costs and provide for more efficient production of natural gas and oil from our properties.

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Pursue Opportunistic Acquisitions.     We review opportunities to acquire producing properties, leasehold acreage and drilling prospects that are located in our core operating areas. We are seeking to acquire properties that provide a strategic fit with our existing activities or that represent new strategic areas that have a proved reserve base coupled with significant exploration or exploitation potential.

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

Hilltop Area, East Texas .    The majority of our activities 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. This exploration play has attracted some of the largest and most active operators in the U.S. Wells in this area target multiple potentially productive natural gas formations and are typically characterized by high initial production, significant decline rates and long-lived reserves.

Our first successful operated well was spudded in 2003 and placed on production in September 2004. As of December 31, 2007, we had successfully completed 14 out of 15 deep Bossier wells and four out of four Knowles Limestone wells. During 2007, we drilled and successfully completed a total of five gross (3.0 net) Bossier wells and three gross (1.5 net) Knowles Limestone wells.

In May 2007, we sold a portion of our undeveloped natural gas and oil acreage in the Hilltop area of East Texas for approximately $66.5 million, net of transaction costs of approximately $1.2 million, resulting in a gain on sale of $38.5 million. We currently have a total of approximately 35,400 gross (16,300 net) acres in the Bossier play. In July 2007, we completed the processing of a 3-D seismic survey purchased earlier in the year. This survey covered all of our retained undeveloped acreage position and is being interpreted and used in the selection of our drilling locations. For 2008, we plan to drill up to three deep Bossier wells and four Knowles Limestone wells.

For the year ended December 31, 2007, net production from the Hilltop area averaged 13.0 MMcf per day. In January 2008, net production from the Hilltop area averaged approximately 20.2 MMcf per day.

Coalbed Methane—Powder River Basin, Wyoming and Montana

We own an approximate 40% average working interest in approximately 55,000 gross (21,900 net) acres in the Powder River Basin of Wyoming and Montana. The Powder River Basin has been an important natural gas 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 the 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 27 (12.5 net) CBM wells. As of December 31, 2007, we had an interest in 283 gross (125.2 net) productive CBM wells producing in the Basin. For the year ended December 31, 2007, our average net production from our CBM properties in the Powder River Basin was approximately 5.1 MMcf per day. We anticipate continuing our recompletion and drilling program in 2008. Our activity level will be influenced by regional natural gas prices, which remained lower than its historic prices relative to Gulf Coast Henry Hub natural gas prices during late 2007. Regional prices in early 2008 have rebounded to, or above, historic price levels.

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

We have a 35% interest in PEL 238, a CBM exploratory property covering approximately 2.2 million gross (786,000 net) acres, located in the Gunnedah Basin of New South Wales, approximately 250 miles northwest of Sydney, Australia, near the town of Narrabri. We believe that the strategic location of the properties and potential CBM reserves near the large natural gas markets in the Sydney-Newcastle-Wollongong area and the concession’s location relative to other developing gas markets should create a competitive marketing 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.

During 2006, we participated with our joint venture partner and license operator, Eastern Star Gas Limited, 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 of PEL 238 and one additional monitoring well. The results from the pilot production phase of the program have been positive, with the results confirming the high measured permeability of the coal and the presence of natural gas in the coal.

During 2007, we and our joint venture partner were approached by potential buyers with an interest in potentially contracting for up to 1 Tcf of natural gas from PEL 238. In March 2007, we announced that we and our joint venture partner had executed a Memorandum of Understanding (“MOU”) with Macquarie Generation, a New South Wales government-owned electricity generator, for the potential future supply of natural gas for its Bayswater power station. Macquarie Generation is Australia’s largest electricity producer and owns and operates two coal fired power stations in the Hunter Valley-Bayswater and Liddell. A long-term natural gas supply and purchase agreement with Macquarie Generation could include up to 500 Bcf to be delivered over a 15 to 20 year period commencing in late 2010, though there is no assurance that such an agreement will ultimately be reached or that such volumes will ultimately be produced from PEL 238. In addition, a potential gas supply and purchase agreement with Macquarie Generation would serve to underpin the development of the approximately 300 kilometers of pipeline infrastructure necessary to transport gas from the PEL 238 concession to Bayswater. An additional 150 kilometers of pipeline infrastructure would be required to access the natural gas markets of Sydney-Newcastle-Wollongong area.

In November 2007, we announced that we and our joint venture partner had entered into a second MOU with Babcock & Brown (“Babcock & Brown MOU”) to supply gas from the PEL 238 and PEL 433 concessions for use in the generation of electricity. The Babcock & Brown MOU envisions the supply of up to 30 Bcf per year of natural gas from the Gunnedah Gas Project to be delivered over multiple years for use in a gas fueled power station to be developed by Babcock & Brown in northern New South Wales, Australia commencing in late 2010. Natural gas sales under the anticipated agreements could be expanded to meet requirements for power station developments at other locations, though there is no assurance that such an agreement will ultimately be reached or that such volumes will ultimately be produced from the PEL 238 and PEL 433 concessions.

In September 2007, our independent petroleum engineers, Netherland Sewell & Associates, Inc. (“NSAI”), certified a quantity of proved and probable reserves under guidelines established by the Society of Petroleum Engineers (“SPE”), as a result of the success of one of our pilot production projects on PEL 238. These reserves, however, are not yet established as proved reserves under Securities and Exchange Commission, or SEC, guidelines nor can we assure that other unevaluated acreage will contain similar reserves.

Petroleum Assessment Lease 2, or PAL 2, was issued by the New South Wales Department of Primary Industries on October 30, 2007. PAL 2, in which Gastar holds a 35% interest, lies within PEL 238 and covers the existing Bohena Project Area of approximately 65,000 gross acres including the Bibblewindi and Bohena Production Pilots, with umbilical areas connecting to the Wilga Park Power Station. The assessment lease, which

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is intended for the area to be assessed for an eventual production lease, allows gas production from the two production pilots to ultimately be transported by a dedicated gas gathering system to the power station for electricity production and sale. We and our joint venture partner are in the permitting phase for the construction of the gathering system and pipeline, which is anticipated to be completed by late 2008.

During 2008, we, together with our joint venture partner intend to expand our pilot production drilling program on the PEL 238 concession. Through a planned development program in PEL 238 consisting of additional production pilot projects and core hole drilling, we are aiming to convert a portion of the substantial gross resource potential into additional certifiable proved and probable reserves as we move towards large-scale commercial production. We anticipate the certification of proved reserves and the growth of our probable reserves as necessary to support the development of infrastructure to service growing natural gas demand in New South Wales. Contracts and capital commitments for the construction of such infrastructure as well as gas sales or use contracts on PEL 238, will be necessary before we can recognize proved reserves under SEC guidelines.

The area on which PEL 238 is located is subject to a native title claim lodged in March 2007 by the Gomeroi Narrabri People (NSD437/07). See “Governmental Regulation-Australian Governmental Regulation-Native Title”.

Coal Bed Methane—PEL 433-434, Gunnedah Basin, New South Wales, Australia

PEL 433 is located south of PEL 238 where Gastar and our joint venture partner, Eastern Star Gas Limited, are developing the Gunnedah Basin Gas Project (Coal Seam Gas Joint Venture). Coal evaluation core-hole drilling completed during the 1970s and 1980s by the New South Wales government identified the distribution and thickness of the coal measures within a portion of PEL 433. The Hoskissons Coal Seam is believed to be approximately 4 to 6 meters thick and widely distributed within the eastern part of PEL 433. There has been no previous coal seam gas exploration and evaluation work in the area, and there is no information on gas content, gas composition or coal permeability.

In July 2007, we entered into a Farm-In Agreement with Eastern Star Gas Limited under which we have earned a 35% working interest in the PEL 433 and adjoining PEL 434 properties. Under the terms of the Farm-In Agreement, we paid the costs of a two core-hole program and the related costs of the evaluation of the coal reservoirs intersected by the core-holes.

The two corehole drilling program commenced during July 2007 and evaluated the coal seam gas potential of the Hoskissons Coal Seam within the Late Permian Black Jack Coal Measures. Additional coring may be undertaken on PEL 433 to provide additional data on coal depth, thickness, permeability, gas contents and composition.

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

The area on which PEL 433 is located is subject to a native title claim lodged in June 2002 by the Tubba-Gah People (NSD6010/02). See “Governmental Regulation—Australian Governmental Regulation—Native Title”.

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

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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. In late 2006, we pre-funded $6.5 million for a 10-well drilling program, which commenced drilling operations in late 2006. The program included the establishment of two “five-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.

Prior to the completion of the 10-well program mentioned above, Gastar and the operator of EL 4416, a subsidiary of GeoStar Corporation (“GeoStar”), became involved in a number of disputes concerning Gastar’s right to an assignment of its interest in EL 4416 and other jointly-owned properties. As a result, the operator has not provided Gastar with information concerning the results of the 10-well drilling program nor an accounting for the use of the funds provided for the drilling of the 10 CBM wells. 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. We have sent a letter to GeoStar demanding the arbitration of these issues. See Item 3, “Legal Proceedings—Arbitration and Litigation with GeoStar Corporation and Affiliates”.

No native title claims have been lodged at this time in relation to the area on which EL 4416 is located. See “Governmental Regulation—Australian Governmental Regulation—Native Title”.

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.

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 any natural gas infrastructure. The initial gas market for PEL 238 natural gas is anticipated to be an electricity generation facility owned and operated by Eastern Star Gas Ltd. 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 in the permitting phase for the construction of the gathering system and pipeline, which is anticipated to be completed by late 2008.

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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. Recent announcements of planned LNG facilities in southern Queensland are to be sourced from coalbed methane projects, which could potentially lead to the possibility of a portion of future PEL 238 production being sold to LNG export facilities. In March 2007, we announced that we had executed, along with our joint venture partner, a 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 Macquarie Generation’s Bayswater power station. In November 2007, we announced that we and our Joint venture partner had entered into a second MOU with Babcock & Brown (“Babcock & Brown MOU”) to supply gas from the PEL 238 and PEL 433 concessions for use in the generation of electricity. The Babcock & Brown MOU envisions the supply of up to 38 Bcf per year of natural gas from the Gunnedah Gas Project over multiple years for use in a gas fueled power station to be developed by Babcock & Brown in northern New South Wales, Australia commencing in late 2010. Natural gas sales under the anticipated agreements could be expanded to meet requirements for power station developments at other locations, though there is no assurance that such an agreement will ultimately be reached or that such volumes will ultimately be produced from the PEL 238 and PEL 433 concessions. In addition, a potential gas supply and purchase agreement with Macquarie Generation would serve to underpin the development of the approximately 300 kilometers of pipeline infrastructure necessary to transport gas from the PEL 238 concession to Bayswater. An additional 150 kilometers of pipeline infrastructure would be required to access the natural gas markets of Sydney-Newcastle-Wollongong area.

The area on which PEL 433 is located is subject to a native title claim lodged in June 2002 by the Tubba-Gah People (NSD6010/02). See “Governmental Regulation – Australian Governmental Regulation-Native Title”.

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 the Appalachian Basin in 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 March 2008, we entered into formal agreements with ETC Texas Pipeline, Ltd. (“ETC”) for the gathering, treating, purchase and transportation of our natural gas production from the Hilltop area of East Texas. These agreements are effective September 1, 2007 and have a term of 10 years. ETC currently provides us 50 MMcfd of treating capacity and 120 MMcfd of gathering capacity. We have the right to request ETC build, at their cost, up to 150 MMcfd of treating and gathering capacity during the term of the agreement, provided that our production equals 85% of the then existing treating and gathering capacity for a 30 day period. We may at any time elect to have our treating and gathering capacity increased subject to cost indemnifications to ETC. Additional treating and gathering capacity requests must be in at least 25 MMcfd and 5 MMcfd increments, respectively. In addition, we must furnish to ETC information that reasonably demonstrates that our projected production for the five years after expansion is sufficient to warrant the costs to create the expanded treating and gathering capacity. The incremental volume increases in treating and gathering capacity shall be subject to marginal increases in treating fees. Pursuant to the agreements, we have access up to 150 MMcfd of firm transportation on ETC’s system or the pipelines of its affiliates or subsidiaries from the tailgate of the treating facility to Katy Hub. We have the option to sell and ETC has the obligation to buy, up to 150 MMcfd of our Hilltop production at delivery points upstream of ETC’s gathering and treating facilities. We do not have an obligation to deliver to ETC volumes in excess of 150 MMcfd, but should ETC elect to purchase such excess volumes, purchases will be subject to the treating and gathering expansion terms set forth in the agreements.

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During 2007, ETC and Enserco Energy, Inc. (“Enserco”) accounted for 78% and 20% of our natural gas and oil revenues, respectively. During 2006, sales to ETC and Enserco 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. Although ETC is the major natural gas purchaser and transporter in the area of our deep Bossier play and only 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 and would minimize any 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, many of whom 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.

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 smaller and have a more limited operating history than most of our competitors 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 providing the manpower to operate them and provide related services.

Governmental Regulation

In addition to the environmental regulations discussed below, 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 prospect or acreage.

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

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regulations, we are unable to predict the future cost or impact of complying with such laws because those laws 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, or 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. The 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 natural gas

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and oil wells; the spacing of wells; and the plugging and abandonment of wells and removal of related production equipment. These regulations can limit the amount 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, or acquisition of urban land will require review and approval under the commonwealth foreign investment policy and regulations.

Native Title.     In a landmark Australian High Court decision in 1992, it was recognized that the native title to land of Indigenous Australians survived the acquisition of sovereignty by the British Crown. However native title to any particular area will only survive to the present if it has not been extinguished subsequently. Native title may be extinguished by the action of government, such as the creation of an interest that is inconsistent with native title. In particular, the grant of the right to exclusive possession through freehold title or a lease will wholly extinguish native title. Native title may also be extinguished if the connection between the land and the group of Aboriginal people claiming native title has been lost. The Native Title Act 1993 (Cth) 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 how dealings affecting native title can be conducted in the future. Native title claims by Aboriginal groups can cover 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 or determinations. To validly affect native title, permits and licenses must be granted in compliance with the Native Title Act 1993 (Cth) .

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 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

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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 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 U.S. natural gas and oil exploration and production operations and similar operations that we do not operate but in which we own a working interest 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

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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 transported, 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 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. In the past, proposals have been made to amend RCRA to rescind this exemption. Repeal or modification of the exception or similar exemptions in state law could increase the amount of hazardous waste we are required to manage and dispose of and could cause us to incur increased operating cost, which could have a significant impact on us as well as 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.

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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 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 CAA 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.

Our CBM production operations involve the use of gas-fired compressors to produce or 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 that have been 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 the 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

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having already been introduced in the Senate that propose to restrict greenhouse gas emissions. One bill recently approved by the U.S. Senate Environment and Public Works Committee, known as the Lieberman-Warner Climate Security Act or S.2191, would require a 70% reduction in emissions of greenhouse gases from sources within the United States between 2012 and 2050. The Lieberman-Warner bill proposes a “cap and trade” scheme of regulation of greenhouse gas emissions or a ban on emissions above a defined reducing annual cap. Covered parties will be authorized to emit greenhouse emissions through the acquisition and subsequent surrender of emission allowances that may be traded or acquired on the open market. A vote on this bill by the full Senate is expected to occur before mid-year 2008. In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs require either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall greenhouse gas emission reduction goal is achieved. Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of fuels (such as natural gas or oil) we produce. Although we would not be impacted to a greater degree than other similarly situated producers of natural gas and oil, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the natural gas and oil we produce.

Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA , the EPA may be required to regulate carbon dioxide and other greenhouse gas emissions from mobile sources, such as cars and trucks even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The EPA has indicated that it will issue a rulemaking notice to address carbon dioxide and other greenhouse gas emissions from vehicles and automobile fuels, although the date for issuance of this notice has not been finalized. The Supreme Court’s holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New federal or state restrictions on emissions of carbon dioxide that may be imposed in areas of the United States in which we conduct business could also adversely affect our cost of doing business and demand for the natural gas and oil we produce.

Finally, legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security, or DHS, 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. The federal Department of Homeland Security Appropriations Act of 2007 required the DHS to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including natural gas and oil facilities that are deemed to present “high levels of security risk”. The DHS issued an interim final rule, known as the Chemical Facility Anti-Terrorism Standards Interim Final Rule, in April 2007 regarding risk-based performance standards to be attained pursuant to the Act and, on November 20, 2007, further issued an Appendix A to the interim rule that establish chemicals of interest and their respective threshold quantities that trigger compliance with this rule. Facilities that possess the threshold quantities of chemicals of interest must submit to an initial screening process for DHS to determine if they present a high level of security risk. Facilities that are deemed to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans and comply with other regulatory requirements including those regarding inspections, audits, recordkeeping and protection of Chemical-terrorism Vulnerability Information. We have not yet determined the extent to which our facilities are subject to the interim rules or the associated costs to comply, but it is possible that such costs could be substantial.

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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.

Australia ratified the Kyoto Protocol on December 3, 2007, and officially committed to meeting its Kyoto Protocol target. Australia set a target to reduce greenhouse gas emissions by 60% on 2000 levels by 2050 and committed to actively participate in negotiations working towards a post 2012 agreement involving developed and developing countries. Australia has introduced a National Greenhouse and Energy Reporting Act 2007 , which establishes a single national system for reporting greenhouse gas emissions, abatement actions and energy consumption and production by corporations from July 1, 2008. Data reported through the system will underpin the Australian Emissions Trading Scheme, or AETS, which is to be introduced by 2010. The consultation stage and detailed design of the AETS is to be finalized by the end of 2008. The government has made it clear that it plans to introduce a “cap and trade scheme” in which total emissions are capped, permits allocated up to the cap and trading allowed to let the market find the cheapest way to meet any necessary emission reductions. As the details of the AETS are not yet finalized, we are unable at this stage to assess the likely impact of the AETS on our operations in Australia.

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.

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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 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.

Industry Segment and Geographic Information

We operate in one industry segment, which is the exploration, development and production of natural gas and oil. Our operational activities are conducted in the United States and Australia with only the United States currently having revenue generating operating results.

Employees

As of March 10, 2008, we had 23 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. We maintained an office in Miami, Florida (our Chief Executive Officer’s city of residence) through April 2007 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 Exchange 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:

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