Overview

We are an independent energy and production company focused on finding and developing natural gas assets in North America. Our emphasis is on combining deep natural gas exploration and development with lower risk shale resource and coal bed methane ("CBM") development. We own and operate exploration and development acreage in the deep Bossier gas play of East Texas and the Marcellus Shale play in West Virginia and Pennsylvania. Our CBM activities are conducted within the Powder River Basin of Wyoming and Montana. We are a Canadian corporation incorporated in Alberta in 1987. We are publicly traded on the NYSE Amex under the ticker symbol "GST".

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, 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 have been in the Bossier play in the Hilltop area of East Texas approximately midway between Dallas and Houston in Leon and Robertson Counties, where we hold approximately 28,100 gross (14,000) net acres. Wells in this area target multiple potentially productive natural gas formations and are typically characterized by high initial production and attractive long-lived per well reserves.

In May 2009, we completed the Wildman Trust #5 well in one of the five potentially productive zones at a restricted initial gross production rate of
15.0 MMcf per day. We currently are recompleting the Wildman Trust #5 in three additional zones. In May 2009, we released our contracted drilling rig in East Texas due to low natural gas prices and to conserve capital. In late October, we returned the contracted rig to drilling in East Texas with the spudding of the Donelson #4 well, an approximate 19,000-foot lower Bossier test. We expect this well will take at least three months to drill. For the remainder of 2009 and fiscal year 2010, we are planning our East Texas capital activity to include three additional lower Bossier exploratory wells and up to 11 recompletions.

For the three months ended September 30, 2009, net production from the Hilltop area averaged 20.0 MMcfe per day after curtailment of approximately 1.9 MMcfe per day due to low natural gas prices.

Marcellus Shale - West Virginia and Central and Southwestern Pennsylvania

The Marcellus Shale is Middle Devonian aged shale that underlies much of Pennsylvania, New York, Ohio,

West Virginia and adjacent states. The depth of the Marcellus Shale and its low permeability make the Marcellus Shale an unconventional exploration target. Advancements in two technologies, stimulation and horizontal drilling, have produced promising results in the Marcellus Shale. 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 central and southwestern Pennsylvania. As of September 30, 2009, our acreage position in the play was approximately 39,300 gross (35,800 net) acres, of which the majority is considered to be in the core, over-pressured area of the Marcellus play and is in close proximity to wells being drilled by other operators.

In October 2009, we commenced drilling our first vertical Marcellus Shale well, the Yoho #1. We drilled the well to a depth of 6,600 feet, and it is currently waiting on fracture simulation and flow testing, which is scheduled to be completed during the first half of November. We currently are seeking pipeline capacity for the well's anticipated production but do not expect any sales until at least mid-year 2010.

During the nine months ended September 30, 2009, we drilled 8 (7.6 net) shallow vertical wells resulting in total shallow wells drilled by us to 15 (13.8. net) in the area. Currently, eight are on production, and the remaining wells are scheduled to be on production in the next 75 days. This shallow well drilling program continues to be conducted to hold certain leases by production. For the three months ended September 30, 2009, net production from the Appalachia area averaged approximately 0.4 MMcfe per day.

For the remainder of 2009 and fiscal year 2010, we currently anticipate that we will drill at least five additional vertical Marcellus wells and up to 15 additional shallow wells.

Coalbed Methane - Powder River Basin, Wyoming and Montana

We own an approximate 40% average working interest in approximately 40,800 gross (17,100 net) acres in the Powder River Basin of Wyoming and Montana. Our 2009 activity level has been influenced by natural gas prices in the area, which for the first nine months of this year have been significantly lower than our other operating areas. As a result, only maintenance type expenditures were incurred during the nine months ended September 30, 2009. No additional drilling is anticipated in the Powder River Basin until long-term natural gas prices increase in the area. As a result of the decrease in drilling activity and curtailments, for the three months ended September 30, 2009 Powder River Basin production averaged 2.9 MMcfe per day.

Australian Coalbed Methane - Petroleum Exploration Licenses 238, 433, and 434 and Wilga Park Power Station

On July 13, 2009, Gastar Exploration New South Wales, Inc. and Gastar Exploration USA, Inc., each a wholly-owned subsidiary of us, completed the sale of all of our interest in Petroleum Exploration Licenses ("PEL") 238 (including Production Petroleum License 3), PEL 433, and PEL 434 in New South Wales, Australia and the concurrent sale of our common shares of Gastar Power Pty Ltd., our wholly owned subsidiary holding our 35% working interest in the Wilga Park Power Station, to Santos QNT Pty Ltd. and Santos International Holdings Pty Ltd.. The sale was made pursuant to a definitive agreement dated July 2, 2009 by and among Gastar New South Wales, Gastar USA and Santos.

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 Nine Months
                                                     Ended September 30,        Ended September 30,
                                                      2009          2008         2009         2008

Production:
Natural gas (MMcf)                                       2,139        1,849        7,155        6,291
Oil (MBbl)                                                   1            1            3            4
Total (MMcfe)                                            2,145        1,856        7,175        6,315

Total (MMcfed)                                            23.3         20.2         26.3         23.0

Average sales prices:
Natural gas (per Mcf), including impact of
realized hedging activities                        $      3.50    $    6.67   $     4.58    $    7.12
Oil (per Bbl)                                      $     61.97    $  111.49   $    51.29    $  104.58

Three months ended September 30, 2009 compared to the Three months ended September 30, 2008

Revenues. Substantially all of our revenues are derived from the production of natural gas in the United States. Natural gas and oil revenues were $7.6 million for the three months ended September 30, 2009, down from $12.5 million for the three months ended September 30, 2008. The decrease in revenues was the result of a 48% decrease in prices, partially offset by a 16% increase in production volumes, primarily in East Texas. During the current quarter, we elected to curtail our East Texas production by approximately 1.9 MMcf per day due to low natural gas prices. During the three months ended September 30, 2009, approximately 81% of our natural gas production was hedged. The realized effect of hedging on natural gas sales for the three months ended September 30, 2009 was an increase of $2.2 million in revenues resulting in an increase in total price received from $2.46 per Mcf to $3.50 per Mcf. The realized effect of hedging on natural gas sales for the three months ended September 30, 2008 was a decrease of $569,000 in revenues, resulting in a decrease in total price received from $6.98 per Mcf to $6.67 per Mcf.

Unrealized natural gas hedge loss was $3.3 million for the three months ended September 30, 2009, compared to hedge income of $3.4 million for the three months ended September 30, 2008.

Production taxes. We reported production taxes of $76,000 for the three months ended September 30, 2009, compared to $340,000 for the three months ended September 30, 2008. The decrease in production taxes was primarily the result of lower natural gas prices and lower production volumes in Wyoming.

Lease operating expenses. We reported lease operating expenses of $1.8 million for the three months ended September 30, 2009, down from $1.9 million for the three months ended September 30, 2008. Our lease operating expenses were $0.82 per Mcfe for the three months ended September 30, 2009, compared to $1.03 per Mcfe for the comparable period in 2008. Excluding workover expense and other non-recurring costs, our lease operating expenses were $0.66 per Mcfe for the three months ended September 30, 2009, compared to $0.95 per Mcfe for the same period in 2008. The decrease in the rate per Mcfe was primarily due to higher current quarter production volumes and a decrease in property taxes of $0.06 per Mcfe due to lower natural gas prices.

Transportation and treating. We reported transportation expenses of $172,000 for the three months ended September 30, 2009, down from $518,000 for the three months ended September 30, 2008. This decrease was primarily due to lower natural gas prices and lower production volumes in Wyoming partially related to the release of certain compressors as part of a program to reduce overall compression costs in Wyoming.

Depreciation, depletion and amortization. We reported depreciation, depletion and amortization ("DD&A") of $3.0 million for the three months ended September 30, 2009, down from $6.1 million for the three months ended September 30, 2008. The decrease in DD&A expense was the result of a 58% decrease in DD&A rate per Mcfe partially offset by a 16% increase in production. The DD&A rate for the three months ended September 30, 2009 was $1.38 per Mcfe, compared to $3.27 for the comparable period in 2008. The decrease in rate is primarily due to lower proved costs due to additional ceiling impairments partially offset by lower proved reserves due to a 54% decline in natural gas prices between the periods. The decrease in natural gas prices resulted in lower economic reserve limits thus reducing total reserves.

General and administrative. We reported general and administrative expenses of $5.2 million for the three months ended September 30, 2009, up from $3.2 million for the three months ended September 30, 2008. Non-cash stock-based compensation expense, which is included in general and administrative expenses, was $633,000 and $731,000 for the three months ended September 30, 2009 and 2008, respectively. Excluding stock-based compensation expense, general and administrative expense increased $2.1 million to $4.5 million for the three months ended September 30, 2009. This increase is primarily due to higher legal costs resulting from ongoing litigation matters and inclusion of $1.1 million of performance bonus related to the successful sale of the Australian assets.

Interest expense. We reported interest expense of $1.0 million for the three months ended September 30, 2009, compared to $913,000 for the three months ended September 30, 2008. The increase in interest expense was primarily the result of a decrease in capitalized interest expense.

Early extinguishment of debt. In conjunction with the repayment of the revolving credit facility, the term loan and the 12 3/4% senior secured notes, we reported debt extinguishment expense of $15.9 million for the three months ended September 30, 2009, comprised of $8.9 million of early prepayment penalty on the term loan and the 12 3/4% senior secured notes and $7.0 million of unamortized deferred financing costs on the debt retired.

Gain on sale of assets. In July 2009, we sold our non-producing Australian assets for approximately $232.6 million before transaction costs of approximately $1.9 million and Australian income taxes of $65.8 million, resulting in a net gain on sale of $127.6 million.

Warrant derivative loss. For the three months ended September 30, 2009, we reported a $495,000 non-cash loss related to the fair value remeasurement of our warrant outstanding.

Foreign transaction gain (loss). We reported a foreign transaction gain of $7.6 million for the three months ended September 30, 2009, compared to a loss of $21,000 for the three months ended September 30, 2008. The increase in foreign transaction gain was due to the increase in Australian denominated cash and cash term deposit balances due to the sale of the Australian properties. Approximately $68.3 million of our cash and cash term deposit continue to be denominated in Australian dollars to allow for the future payment of Australian income taxes in June 2010.

Nine months ended September 30, 2009 compared to the Nine months ended September 30, 2008

Revenues. Substantially all of our revenues are derived from the production of natural gas in the United States. Natural gas and oil revenues were $33.0 million for the nine months ended September 30, 2009, down from $45.2 million for the nine months ended September 30, 2008. The decrease in revenues was the result of a 36% decrease in prices, partially offset by a 14% increase in production volumes, primarily in East Texas. We elected to curtail our East Texas production in the third quarter of 2009 due to low natural gas prices, reducing our year-to-date production by approximately 0.6 MMcf per day. During the nine months ended September 30, 2009, approximately 79% of our natural gas production was hedged. The realized effect of hedging on natural gas sales for the nine months ended September 30, 2009 was an increase of $11.8 million in revenues resulting in an increase in total price received from $2.93 per Mcf to $4.58 per Mcf. The realized effect of hedging on natural gas sales for the nine months ended September 30, 2008 was a decrease of $3.4 million in revenues, resulting in a decrease in total price received from $7.67 per Mcf to $7.12 per Mcf. We have fourth quarter 2009 costless collar or call price hedge protection for approximately 11,600 MMBtu per day at a weighted average NYMEX MMBtu put price of $4.06 and a call price of $5.89. In addition, for the fourth quarter of 2009, we own $5.00 puts for approximately 11,500 MMBtu per day, which assures us protection in price environments below that $5.00 NYMEX level without limiting any upside price participation opportunity.

Unrealized natural gas hedge loss was $7.9 million for the nine months ended September 30, 2009, compared to $1.5 million of hedge income for the nine months ended September 30, 2008. The decrease in unrealized natural gas loss was the result of a decrease in natural gas prices and the monetization of certain hedge contracts during 2009.

Production taxes. We reported production taxes of $325,000 for the nine months ended September 30, 2009, compared to $1.1 million for the nine months ended September 30, 2008. The decrease in production taxes was primarily the result of lower natural gas prices and lower production volumes in Wyoming.

Lease operating expenses. We reported lease operating expenses of $5.1 million for the nine months ended September 30, 2009, down from $5.9 million for the nine months ended September 30, 2008. Our lease operating expenses were $0.71 per Mcfe for the nine months ended September 30, 2009, compared to $0.93 per Mcfe for the comparable period in 2008. Excluding workover expense and other non-recurring costs, our lease operating expenses were $0.61 per Mcfe for the nine months ended September 30, 2009, compared to $0.76 per Mcfe for the same period in 2008. The decrease in the rate per Mcfe was primarily due to higher production volumes.

Transportation and treating. We reported transportation expenses of $990,000 for the nine months ended September 30, 2009, down from $1.5 million for the nine months ended September 30, 2008. This decrease was primarily due to lower natural gas prices and lower production volumes in Wyoming, partially related to release of certain compressors as part of a program to reduce overall compression costs in Wyoming.

Depreciation, depletion and amortization. We reported depreciation, depletion and amortization ("DD&A") of $14.3 million for the nine months ended September 30, 2009, down from $18.4 million for the nine months ended September 30, 2008. The decrease in DD&A expense was the result of a 31% decrease in DD&A rate per Mcfe, partially offset by a 14% increase in production. The DD&A rate for the nine months ended September 30, 2009 was $1.99 per Mcfe, compared to $2.91 for the comparable period in 2008. The decrease in rate was primarily due to lower proved costs due to additional ceiling impairments taken and lower proved reserves attributable to a significant decline in natural gas prices.

Impairment of natural gas and oil properties. We reported impairment of natural gas and oil properties of $68.7 million for the nine months ended September 30, 2009. The 2009 impairment was recorded at March 31, 2009 and was the result of a significant decline in natural gas prices in 2009. The March 31, 2009 quarter end Henry Hub natural gas price declined 37% from December 31, 2008 price resulting in estimated future net revenues being based on a weighted average price of $2.64 per Mcf at March 31, 2009, compared to $4.56 per Mcf at year end 2008. There was no impairment for the comparable period in 2008 due to higher natural gas and oil prices.

General and administrative. We reported general and administrative expenses of $11.6 million for the nine months ended September 30, 2009, compared to $11.5 million for the nine months ended September 30, 2008. Non-cash stock-based compensation expense, which is included in general and administrative expenses, was $2.8 million and $2.4 million for the nine months ended September 30, 2009 and 2008, respectively. This increase in stock-based compensation expense was due to the March 2009 payment of 2008 management bonuses of $801,000 in vested restricted common shares in lieu of cash bonuses. Excluding stock-based compensation expense, general and administrative expense decreased $253,000 to $8.8 million for the nine months ended September 30, 2009. This decrease was primarily due to lower personnel costs and the payment of 2008 management bonuses in restricted common shares, which was partially offset by the inclusion of $1.1 million of performance bonus related to the successful sale of the Australian assets and higher legal costs related to ongoing litigation matters.

Interest expense. We reported interest expense of $3.3 million for the nine months ended September 30, 2009, compared to $4.9 million for the nine months ended September 30, 2008. The decrease in interest expense was primarily the result of a $2.2 million increase in interest capitalized during the nine months ended September 30, 2009, which was partially offset by higher interest expense on our term loan and revolving credit facility.

Early extinguishment of debt. In conjunction with the repayment of the revolving credit facility, the term loan and the 12 3/4% senior secured notes we reported debt extinguishment expense of $15.9 million for the nine months ended September 30, 2009, comprised of $8.9 million of early prepayment penalty on the term loan and the 12 3/4% senior secured notes and $7.0 million of unamortized deferred financing costs on the debt retired.

Gain on sale of assets. In July 2009, we sold our non-producing Australian assets for approximately $236.6 million before transaction costs of approximately $1.9 million and Australian income taxes of $65.8 million, resulting in a gain on sale of $127.6 million.

Warrant derivative loss. For the nine months ended September 30, 2009, we reported a $495,000 non-cash loss related to the fair value remeasurement of our warrants outstanding.

Foreign transaction gain (loss). We reported a foreign transaction gain of $7.6 million for the nine months ended September 30, 2009, compared to a loss of $59,000 for the nine months ended September 30, 2008. The increase in foreign transaction gain was due to the increase in Australian denominated cash and cash term deposit balances due to the sale of the Australian assets. Approximately $68.3 million of our cash and cash term deposit continue to be denominated in Australian dollars to allow for the future payment of Australian income taxes in June 2010.

Liquidity and Capital Resources

Overview. Our primary sources of liquidity and capital resources are internally generated cash flows from operating activities or asset sales, availability under our revolving credit facility, and access to capital markets, to the extent available. The capital markets, as they relate to us, have been adversely impacted by the continuing financial crisis, the possibility of a deepening world recession that may extend for a long period into the future, a lack of liquidity in the banking system and the unavailability and cost of credit. Though recently there has been some improvement in the capital markets, there is no guarantee that such will continue. We continually evaluate our capital needs and compare them to our capital resources and ability to raise funds in the financial markets. We adjust capital expenditures in response to changes in natural gas and oil prices, drilling results and cash flow.

For the nine months ended September 30, 2009, we reported cash flow from operating activities of $12.7 million, net cash provided by investing activities of $129.2 million, including cash proceeds from the sale of our Australian assets, net of transaction costs of $229.5 million before tax expense, and net cash used by financing activities of $120.4 million. As a result of these activities, our cash and cash equivalents increased by $21.5 million, resulting in a September 30, 2009 balance of cash and cash equivalents of $27.6 million. We also invested AU$60.0 million ($52.4 million) in a cash term deposit that will mature on June 1, 2010. The cash term deposit is denominated in Australian dollars and pledged to be used to pay a portion of the accrued Australian tax payable resulting from the sale of our Australian assets.

On July 13, 2009, we completed the sale of all of our Australian assets to Santos for an aggregate purchase price of $232.6 million (AU$300.0 million), before transaction costs of $1.9 million and estimated Australian taxes of $65.8 million (AU$80.0 million), resulting in a gain on the sale of assets of $127.6 million. To date, we have received approximately 231.0 million (AU$298.0 million), excluding taxes and transaction expenses and are scheduled to receive the balance upon receipt of certain government approvals. In the event such governmental approval is not obtained by April 3, 2010, Santos will retain the remaining approximate $1.6 million (AU$2.0 million) and will take all necessary actions to transfer the participating interest, excluding PEL 238, PEL 433, and PEL 434, back to us. We may be paid, assuming quarter end foreign exchange rates and before any Australian taxes, an additional approximate $17.5 million (AU$20.0 million) in early 2010 if certain gross reserve certification targets for the PEL 238 CBM project are achieved by Santos and the operator of the properties. The sale agreement also acknowledges our retention of our right to future cash payments of up to $10.0 million pursuant to a pre-existing farm-in agreement in the event certain production thresholds are reached on PEL 238. Neither the gross reserve certification target receivable nor the production threshold receivable were accrued as of September 30, 2009, as the probability of earning the receivables was not determinable.

On July 13, 2009, we used approximately $27.5 million of the proceeds from the sale of the Australian assets to repay in full the term loan and $13.0 million to repay the outstanding amount on our secured revolving credit facility. On August 7, 2009, we repurchased all of our outstanding $100.0 million 12 3/4% senior secured notes at a price of 106.375% of par, plus accrued and unpaid interest, in accordance with the terms of the governing indenture by tendering payment of $108.7 million to the noteholders. During the third quarter, we also repaid, at par, $10.3 million of our convertible subordinated debentures and the remaining $300,000 of the subordinated unsecured note payable.

At September 30, 2009, we had a net working capital deficit of approximately $18.2 million, with $19.7 million classified as current portion of long-term debt, representing the remaining balance of our convertible subordinated debentures scheduled to mature on November 20, 2009. On October 28, 2009, we executed an amended and restated revolving credit facility, which provides for an initial borrowing base of $47.5 million and is scheduled to mature on January 2, 2013. We have sufficient cash and, if necessary, availability under our revolving credit facility to repay the convertible subordinated debentures and not interrupt our planned exploration and development activities in East Texas and West Virginia.

Future capital and other expenditure requirements. Capital expenditures for the remainder of 2009 and 2010 are projected to be approximately $66.2 million, consisting of $37.8 million in East Texas, $24.6 million in the Marcellus Shale, $1.4 million in the Powder River Basin, and an additional $2.4 million for capitalized interest and other costs. We plan on funding this capital activity through existing cash balances, internally generated cash flow from operating activities and short-term access to availability under our revolving credit facility.

Commodity prices. Our cash flow and ability to raise capital are highly dependent upon the price of natural gas. Material decreases in natural gas prices during recent months have significantly and adversely affected our cash flows from operating activities. In order to reduce our exposure to fluctuations in the price of natural gas, we entered into various costless collars, puts and other hedging transactions with counterparties in 2008 and 2009. We have fourth quarter 2009 costless collar or call price hedge protection for approximately 11,600 MMBtu per day at a weighted average NYMEX MMBtu put price of $4.06 and a call price of $5.89. In addition, for the fourth quarter of 2009, we own $5.00 puts for approximately 11,500 MMBtu per day which assures us protection in price environments below that $5.00 NYMEX level without limiting any upside price . . .