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. Gastar pursues a strategy combining select higher risk, deep natural gas exploration prospects with lower risk coal bed methane (CBM) development. Gastar owns and operates exploration and development acreage in the deep Bossier gas play of East Texas and has recently commenced exploration operations in the Marcellus Shale play in West Virginia and Pennsylvania. Gastar's CBM activities are conducted within the Powder River Basin of Wyoming and Montana and on approximately 6.0 million gross acres controlled by us and our joint development partner in Australia's Gunnedah Basin, located in New South Wales.

Hilltop Area, East Texas

Hilltop Area, East Texas. The majority of our drilling activities have been in the deep Bossier and Knowles Limestone plays 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 United States. 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 June 30, 2008, we had successfully completed 16 out of 17 deep Bossier wells and five out of five Knowles Limestone wells. As of June 30, 2008, we were drilling 1 gross (0.5 net) Bossier well and 1 gross (0.5 net) Knowles Limestone well.

During the three months ended June 30, 2008, we completed the drilling of the Lone Oak Ranch #6, or LOR #6, well to a total depth of 16,475 feet and, based on drilling and log analysis, we encountered two productive middle Bossier sands. The well was initially completed in the deepest pay zone and placed on production at a gross sales rate of 17.5 MMcfd with flowing casing pressure of 9,200 psi. The well was subsequently completed in the upper zone and is currently producing at a rate of 10.6 MMcfd with flowing casing pressure of 6,200 psi. We are currently evaluating the optimal time to co-mingle the production from both zones. Gastar has a 50% working interest before payout (approximately 37.5% net revenue interest) in the LOR #6 well.

During the quarter, we also side-tracked and completed the LOR #4, a horizontal Knowles Limestone well, which currently is producing at a stabilized gross stabilized sales rate of 1.2 MMcfd. Gastar has a 50.0% working interest (approximately 37.5% net revenue interest) in the LOR #4 well.

The Brunette #1, a horizontal Knowles Limestone well, was drilled to a total measured depth of 15,251 feet (total vertical depth of 13,341 feet). The well encountered approximately 640 feet of reservoir quality formation within the 1,367-foot horizontal section of the wellbore. The Brunette #1 was stimulated and placed on production in mid-April 2008 and is currently producing at a gross stabilized rate of 0.3 MMcf per day. The well appears to have mechanical problems, and we anticipate initiating workover procedures in the near future.

Currently, we are drilling one deep Bossier well, the Belin #1, (an offset to the Wildman #3) and one middle Bossier well, the Lone Oak Ranch #7, (an offset to the LOR #6).

For the three and six months ended June 30, 2008, net production from the Hilltop area averaged 16.4 MMcfe per day and 18.6 MMcfe per day, respectively. For the balance of 2008, we anticipate a two-rig drilling program in East Texas focused on drilling Bossier wells offsetting recent successful wells.

Marcellus Shale - West Virginia and Pennsylvania

The Marcellus Shale, is a black shale of Middle Devonian age that underlies much of Pennsylvania, New York, Ohio, West Virginia and adjacent states. The depth of the Marcellus Shale and its low permeability have historically made the Marcellus an unconventional exploration target. Within the past few years, two technologies, hydrofracing and horizontal drilling, have been tested in the Marcellus Shale with very promising results. These developments have resulted in increased leasing and drilling activity in the area. In late 2007, we began acquiring an acreage position in the Marcellus Shale in West Virginia and Eastern Pennsylvania. For the remainder of 2008, we plan to continue to build our lease acreage position in this area. We anticipate that drilling in the Marcellus Shale will commence in late 2008 or early 2009.

Coalbed Methane - Powder River Basin, Wyoming and Montana

We own an approximate 40% average non-operated working interest in approximately 55,000 gross (21,900 net) acres in the Powder River Basin of Wyoming and Montana. 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.

We had no drilling activity in the Powder River Basin during the three months ended June 30, 2008 but anticipate an increase in capital activity later this year. For both of the three and six months ended June 30, 2008, our average net production from our CBM properties in the Powder River Basin was approximately
5.5 MMcf per day.

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 ("NSW"), 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.

During 2006, we participated with our joint venture partner and license operator, Eastern Star Gas Limited ("ESG"), 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 ESG were approached by potential buyers with an interest in potentially contracting for up to 1.0 Tcf of natural gas from PEL 238 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 March 2007, we announced that we and ESG 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. In November 2007, we announced that we and ESG had entered into a second MOU with Babcock & Brown to supply gas from the PEL 238 and PEL 433 concessions for use in the generation of electricity.

In September 2007, our independent petroleum engineers, Netherland Sewell & Associates, Inc., certified a quantity of proved and probable reserves under guidelines established by the Society of Petroleum Engineers, 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.

Beginning in 2008, we and ESG expanded our pilot production drilling program in the Bohena Project Area of PEL 238 and have successfully completed the drilling of the first three test coreholes, the Dewhurst #2, #3 and #4, in a 20-corehole exploration and appraisal drilling program on PEL 238. The results of the coreholes confirmed the presence of a thick Bohena coal seam developed to the south and east of the Bibblewindi pilot production area. The Dewhurst #2 encountered approximately 39 meters of coal within the Black Jack and Maules Creek coal formations, including approximately 18 meters in the targeted Bohena seam of which 14.7 meters was found in a single coal zone. The Dewhurst #3 encountered approximately 39 meters of coal within the Black Jack and Maules Creek coal formations, including approximately 17 meters in the targeted Bohena seam. We recently finished drilling the third corehole, the Dewhurst #4. The well encountered 39 meters of coal within the Black Jack and Maules Creek formations, including 16 meters in the Bohena seam. We are currently drilling the Dewhurst #7.

In late June 2008, we announced, subject to certain approvals, an agreement to acquire a 35% interest in the Wilga Park Power Station in New South Wales, Australia from ESG, which owns the remaining 65% interest. This acquisition aligns both of our ownerships in PEL 238 and the Wilga Park Power Station. The power station is located approximately 20 miles north of the Bohena Project Area of PEL 238. The acquisition also includes a 35% working interest in Petroleum Production License 3, which contains the Coonarah conventional gas field. Upon closing, anticipated in the third quarter of 2008, we will pay $3.0 million in cash to ESG, with an additional payment of $250,000 contingent upon the Wilga Park Power Station being successfully expanded to a capacity of seven megawatts ("MW"). The facility currently has a capacity of four MW with plans in place to gradually increase capacity up to 40 MW as coal seam gas production from PEL 238 increases. Construction of a flowline to deliver gas from the PEL 238 production pilots to the power station is in the final stages of permitting and right-of-way acquisition and is expected to be completed by the end of 2008. The power station will be the primary market for natural gas from PEL 238 until we begin fulfilling our supply arrangements under the two previously announced MOUs.

In July 2008, we and ESG entered into a Heads of Agreement ("HoA") with the APA Group ("APA"), owner of the Central West and Moomba Sydney Gas Pipelines. Under the HoA, options for early delivery of coal seam gas from PEL 238 into NSW gas market are to be investigated. Under the HoA, it is anticipated that coal seam gas would be initially delivered to New South Wales gas markets via APA's Central West Pipeline, with APA's NSW pipeline system to subsequently be expanded as gas production and markets grow. By matching gas production, pipeline and market requirements in this manner, we and ESG believe we can minimize capital requirements, while realizing favorable gas transportation tariffs.

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

PEL 433 and PEL 434 are located adjacent to our PEL 238 project and cover approximately 3.8 million gross (1.3 million net) acres. 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 ESG under which we have earned a 35% working interest in the PEL 433 and PEL 434. Under the terms of the Farm-In Agreement, we paid the costs of a two core-hole program on PEL 433 and the related costs of the evaluation of the coal reservoirs intersected by the core-holes. A two corehole drilling program, designed to evaluate the coal seam gas permeability, gas content and gas composition, was completed in early 2008. The results from these wells showed good coal development, gas composition and excellent permeability in the area. Gas contents were low due to the shallow dept of the coal. Further investigation is underway to identify areas with improved gas content. Analysis of the core samples is continuing. This two corehole program fulfilled the first year capital expenditure commitment for PEL 433.

Both PEL 433 and 434 are set to expire February 2009. We and ESG plan to submit a renewal application including a drilling program to meet work commitment during the term of the renewal. As is customary, we and ESG anticipate that a renewal will necessitate a relinquishment of up to 25% of our current acreage.

Results of Operations

The following is a comparative discussion of the results of operations for the periods indicated. It should be read in conjunction with the condensed consolidated financial statements and the related notes to the condensed consolidated financial statements found elsewhere in this Form 10-Q.

The following table gives information about production volumes and prices of natural gas and oil for the periods indicated:

                                                      For the Three Months       For the Six Months
                                                         Ended June 30,            Ended June 30,
                                                        2008          2007        2008         2007
Production:
Natural gas (MMcf)                                         2,036       1,358         4,442      2,611
Oil (MBbl)                                                     2           2             3          6
Total (MMcfe)                                              2,046       1,372         4,459      2,644

Total (MMcfed)                                              22.5        15.1          24.5       14.6

Average sales prices:
Natural gas (per Mcf), including impact of
realized hedging activities                         $       7.71    $   5.75   $      7.30    $  5.80
Oil (per Bbl)                                       $     105.43    $  63.06   $    102.00    $ 58.49

Three Months Ended June 30, 2008 compared to the Three Months Ended June 30, 2007

Revenues. Substantially all of our revenues are derived from the production of natural gas in the United States. Natural gas and oil revenues were $15.9 million for the three months ended June 30, 2008, up 100% from $8.0 million for the three months ended June 30, 2007. Of the increase in revenues, 49% was the result of a 49% increase in production volumes, primarily in East Texas, and 51% was due to a 34% increase in prices. During the three months ended June 30, 2008, approximately 61% of our total natural gas production was hedged. The realized effect of hedging on natural gas sales was a decrease of $2.6 million in revenues, resulting in a decrease in total price received from $9.01 per Mcf to $7.71 per Mcf.

Unrealized natural gas hedge loss of $513,000 is related to the time value of the costless collars. For the remainder of 2008, we have approximately 50% of our estimated natural gas production hedged.

Production taxes. We reported production taxes of $474,000 for the three months ended June 30, 2008, compared to $220,000 for the three months ended June 30, 2007. The increase in production tax was primarily the result of higher production and prices, primarily in Wyoming, and a severance tax refund in the second quarter of 2007 for our Texas wells.

Lease operating expenses. We reported lease operating expenses of $2.4 million for the three months ended June 30, 2008, up from $1.5 million for the three months ended June 30, 2007. Our lease operating expenses were $1.18 per Mcfe for the three months ended June 30, 2008, compared to $1.10 per Mcfe for the comparable period in 2007. The increase in total lease operating expenses was due to an increase in Texas workover costs coupled with higher production volumes. During the current quarter, workover costs totaled $952,000, or $0.47 per Mcfe, as compared to $276,000, or $0.20 per Mcfe for the same period in 2007. Excluding workover costs, lease operating costs for the three months ended June 30, 2008 were $0.71 per Mcfe, as compared to $0.90 per Mcfe for the same period in 2007.

Transportation and treating. We reported transportation expenses of $498,000 for the three months ended June 30, 2008, up from $339,000 for the three months ended June 30, 2007. This increase was primarily due to increased production and prices of natural gas in Wyoming.

Depreciation, depletion and amortization. We reported depreciation, depletion and amortization ("DD&A") of $5.9 million for the three months ended June 30, 2008, up from $5.4 million for the three months ended June 30, 2007. The increase in DD&A expense was primarily the result of an increase in production volumes of 49%. The DD&A rate for the three months ended June 30, 2008 was $2.88 per Mcfe, as compared to $3.97 per Mcfe for the comparable period in 2007.

Impairment of natural gas and oil properties. There was no impairment of natural gas and oil properties recorded during the three months ended June 30, 2008. We recorded a $28.5 million impairment of natural gas and oil properties for the three months ended June 30, 2007. The weighted average natural gas price utilized for the June 30, 2007 ceiling impairment evaluation was $5.75 per Mcf, held constant.

General and administrative. We reported general and administrative expenses of $4.1 million for the three months ended June 30, 2008, up from $3.5 million for the three months ended June 30, 2007. The increase in general and administrative expenses was primarily due to an increase in legal costs and higher personnel costs. Legal costs related to the GeoStar litigation totaled approximately $968,000 in the current quarter an increase of $859,000 from the same period in 2007. Non-cash stock-based compensation expense pursuant to the SFAS 123R, which is included in general and administrative expenses, was $855,000 and $931,000 for the three months ended June 30, 2008 and 2007, respectively.

Interest expense. We reported interest expense of $1.9 million for the three months ended June 30, 2008, compared to $3.7 million for the three months ended June 30, 2007. The decrease in interest expense was primarily the result of $2.6 million of interest being capitalized during the three months ended June 30, 2008, resulting from capital activity expansion, which was partially offset by higher interest expense on the new 12 3/4% Senior Secured Notes. There was no capitalized interest recorded for the comparable period in 2007.

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

Six Months Ended June 30, 2008 compared to the Six Months Ended June 30, 2007

Revenues. Substantially all of our revenues are derived from the production of natural gas in the United States. Natural gas and oil revenues were $32.7 million for the six months ended June 30, 2008, up 112% from $15.5 million for the six months ended June 30, 2007. Of the increase in revenues, 62% was the result of a 69% increase in production volumes, primarily in East Texas, and 38% was due to a 25% increase in prices. During the six months ended June 30, 2008, approximately 51% of our natural gas production was hedged. The realized effect of hedging on natural gas sales was a decrease of $2.9 million in revenues, resulting in a decrease in total price received from $7.95 per Mcf to $7.30 per Mcf.

Unrealized natural gas hedge loss of $1.9 million is related to the time value of the costless collars. For the remainder of 2008, we have approximately 50% of our estimated natural gas production hedged.

Production taxes. We reported production taxes of $743,000 for the six months ended June 30, 2008, compared to $514,000 for the six months ended June 30, 2007. The increase in production taxes was the result of higher production and prices, primarily in Wyoming, and a severance tax refund in the second quarter of 2007 for our Texas wells.

Lease operating expenses. We reported lease operating expenses of $4.0 million for the six months ended June 30, 2008, up from $3.2 million for the six months ended June 30, 2007. Our lease operating expenses were $0.89 per Mcfe for the six months ended June 30, 2008, compared to $1.21 per Mcfe for the comparable period in 2007. The increase in total lease operating expenses was due to higher Texas workover costs coupled with higher production volumes. During the current period, workover costs totaled $933,000, or $0.21 per Mcfe, as compared to $331,000, or $0.13 per Mcfe during the same period in 2007. Excluding workover costs, lease operating costs for the six months ended June 30, 2008 was $0.68 per Mcfe, as compared to $1.08 per Mcfe for the same period in 2007.

Transportation and treating. We reported transportation expenses of $957,000 for the six months ended June 30, 2008, up from $662,000 for the six months ended June 30, 2007. This increase was primarily due to increased production and prices in Wyoming.

Depreciation, depletion and amortization. We reported DD&A of $12.3 million for the six months ended June 30, 2008, up from $9.8 million for the six months ended June 30, 2007. The increase in DD&A expense was the result of a 69% increase in production, primarily attributable to new East Texas wells. The DD&A rate for the six months ended June 30, 2008 was $2.76 per Mcfe, as compared to $3.70 per Mcfe for the comparable period in 2007.

Impairment of natural gas and oil properties. There was no impairment recorded during the six months ended June 30, 2008. We recorded a $28.5 million impairment of natural gas and oil properties for the six months ended June 30, 2007. The weighted average natural gas price utilized for the June 30, 2007 ceiling impairment evaluation was $5.75 per Mcf, held constant.

General and administrative. We reported general and administrative expenses of $8.3 million for the six months ended June 30, 2008, down from $10.3 million for the six months ended June 30, 2007. This decrease in general and administrative expenses was primarily due to a $3.6 million allowance for doubtful accounts established for certain GeoStar receivables during the six month period ended June 30, 2007. Excluding this GeoStar allowance, general and administrative expenses were up $1.6 million due to higher legal and personnel costs. Legal costs related to the GeoStar litigation totaled approximately $1.7 million for the six months ended June 30, 2008, an increase of $1.6 million for the same period in 2007. Non-cash stock-based compensation expense pursuant to the SFAS 123R, which is included in general and administrative expenses, was $1.7 and $2.2 million for the six months ended June 30, 2008 and 2007, respectively.

Litigation settlement expense. There was no litigation settlement expense for the six months ended June 30, 2008. The $1.4 million litigation settlement expense incurred in the six months ended June 30, 2007 was primarily the result of an accrual related to a proposed settlement with GeoStar on certain matters, which was not settled during the period.

Interest expense. We reported interest expense of $4.0 million for the six months ended June 30, 2008, compared to $7.7 million for the six months ended June 30, 2007. The decrease in interest expense was primarily the result of $5.0 million of interest being capitalized during the six months ended June 30, 2008, resulting from capital activity expansion, which was partially offset by higher interest expense on the new 12 3/4% Senior Secured Notes. There was no capitalized interest recorded for the comparable period in 2007.

Liquidity and Capital Resources

At June 30, 2008, we had cash and cash equivalents of $42.0 million. The administrative agent to our Revolving Credit Facility has recently approved, subject to the agreement of our other syndication banks, an increase in our borrowing base to $45.0 million, of which $6.5 million is being utilized as collateral for a letter of credit to support the Company's hedging activities. This increase will provide us with an additional $38.5 million of borrowing capacity availability under our Revolving Credit Facility. For the six months ended June 30, 2008, we reported cash flow from operations of $24.3 million, up from $5.7 million of cash flow from operations for the six months ended June 30, 2007. This increase resulted primarily from a 69% increase in production volumes and a 25% increase in prices. Capital expenditures on natural gas and oil properties totaled $66.2 million for the six months ended June 30, 2008, including $25.8 million related to the GeoStar settlement regarding the look-back dispute.

Covenants in our 12 3/4% Senior Secured Notes indenture, our indenture governing our 9.75% convertible senior unsecured subordinated debentures and our Revolving Credit Facility agreement require us to make an offer to repurchase or repay all of the outstanding indebtedness thereunder in the event of a change of control of the Company, as defined in the respective agreements. Each of the indentures provides that if there is a change of control of the Company, we are required to make an offer to each holder to repurchase all or any part of the 12 3/4% Senior Secured Notes or the 9.75% convertible senior unsecured subordinated debentures, as the case may be, at 101% of the aggregate principal amount of the notes or debentures tendered for repurchase, plus accrued and unpaid interest. In the event of a change of control, as defined in the Revolving Credit Facility agreement, all obligations under the Revolving Credit Facility will become immediately due and payable. If the change of control event occurs in one or more of these agreements, we may not have adequate financing available to meet the resulting payment obligations.

We continually evaluate our capital needs and compare them to our capital resources. To execute our operational plans in East Texas, Appalachia 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, sales of assets and the issuance of additional debt or equity. We may also attempt to balance future capital expenditures through joint venture development of certain properties with industry partners. We cannot be certain that future funds will be available to fully execute our current business plan.

Based on our current budget, we have sufficient capital, together with . . .