Exhibit 99.1

	NEWS RELEASE
	Contact:
	Gastar Exploration Ltd.
	J. Russell Porter, Chief Executive Officer
	713-739-1800 / rporter@gastar.com
	Investor Relations Counsel:
	Lisa Elliott / Anne Pearson
	DRG&E: 713-529-6600
	lelliott@drg-e.com / apearson@drg-e.com

FOR IMMEDIATE RELEASE

GASTAR EXPLORATION REPORTS FOURTH QUARTER AND

FULL YEAR 2008 FINANCIAL AND OPERATIONAL RESULTS

HOUSTON, March 16, 2009 – Gastar Exploration Ltd. (NYSE Alternext US: GST and TSX: YGA) today reported financial and operational results for the three months and full year ended December 31, 2008.

Some of the highlights include:

• 29% increase in natural gas production to 23.3 MMcfe per day for full-year 2008, compared to 18.1 MMcfe per day in 2007;

• 16% increase in proved natural gas reserves to 63.8 Bcfe;

• 204% U.S. reserve replacement ratio at a cost of $2.82 per Mcfe; and

• 18% sequential increase in fourth quarter total daily production to 23.9 MMcfe and 25% sequential increase in fourth quarter Texas daily production to 18.1 MMcfe per day.

Fourth Quarter Results

Net loss adjusted to exclude impairment charges and unrealized hedging gains was $806,000, or $0.00 per share, for the fourth quarter of 2008. Including a non-cash impairment of natural gas and oil properties of $14.2 million, partly offset by an unrealized hedging gain of $5.0 million, the reported net loss for the quarter was $10.0 million, or $0.05 per share. This compares to an adjusted net loss of $2.4 million, or $0.01 per share, for the fourth quarter of 2007, excluding a debt extinguishment expense of $15.7 million, of which $12.0 million was non-cash, related to the refinancing of the Company’s senior secured notes in November 2007 and a $336,000 reduction in the gain on the sale of unproved properties. Including these charges, the reported net loss for the fourth quarter of 2007 was $18.4 million, or $0.09 per share.

Net cash flows used in operating activities for the three months ended December 31, 2008 was $1.1 million, compared to $2.7 million for the comparable period in 2007.

Excluding the unrealized gas hedge gain, natural gas and oil revenues in the fourth quarter of 2008 increased 23% to $11.5 million. Of this increase, 71% was due to higher natural gas production, primarily from new wells in East Texas, and 29% was due to higher prices. In the fourth quarter of 2008, including the $5.0 million of unrealized gas hedge gain, revenues increased 77% to $16.5 million, compared to revenues of $9.3 million for the comparable period in 2007.

Average daily production for the fourth quarter of 2008 was 23.9 MMcfe, an increase of 17%, compared with 20.5 MMcfe for the fourth quarter of 2007 and an 18% increase over the third quarter of 2008. The average price for natural gas including realized hedging activities increased in the fourth quarter of 2008 to $5.23 per Mcf, from $4.91 per Mcf in the fourth quarter of 2007. Excluding the benefit of the realized hedges, the average realized price in the fourth quarter of 2008 was $4.77 per Mcf.

Lease operating expense (LOE) was $1.7 million in the fourth quarter of 2008, compared to $1.4 million in the fourth quarter of 2007. LOE per Mcfe increased 6% to $0.77 in the fourth quarter of 2008, compared to $0.73 per Mcfe during the fourth quarter of 2007. This increase per Mcfe was primarily due to higher ad valorem taxes, partially offset by lower workover costs.

Year-End Reserves

Total proved reserves as of December 31, 2008 were 63.7 Bcf of natural gas and 12,000 barrels of oil, or 63.8 Bcfe, of which 63% was proved developed reserves. The present value of estimated future cash flows, discounted at 10% per year, was $110.1 million as of December 31, 2008, based on the weighted average natural gas price, after basis adjustments and deductions, of $4.56 per Mcf. Total proved reserves as of December 31, 2007 were 54.8 Bcf of natural gas and 9,000 barrels of oil, or 54.9 Bcfe, of which 62% was proved developed reserves. The present value of estimated future cash flows, discounted at 10% per year, was $132.2 million as of December 31, 2007, based on the weighted average natural gas price, after basis adjustments and deductions, of $6.08 per Mcf. The reserve replacement ratio for U.S. activities in 2008 was 204%, including revisions, at a reserve replacement cost of $2.82 per Mcfe. Approximately 56.8 Bcfe, or 89% of the 2008 proved reserves, are from the East Texas properties, of which 62% is in the proved developed category. Finding and development cost associated with 2008 reserve additions in East Texas was $2.71 per Mcfe on costs of $51.4 million.

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Operations Review and Update

In East Texas, for the three months and full year ended December 31, 2008, net production from the Hilltop area averaged 18.1 MMcfe per day and 17.4 MMcfe per day, respectively. Capital expenditures for the fourth quarter of 2008 in East Texas were approximately $14.9 million to recomplete three wells and bring five additional zones on production, as well as to drill and complete the Belin #1 and drill the Lone Oak Ranch (“LOR”) #7. The Belin #1, which was completed in two lower Bossier zones, is our best producer to date, with an initial production rate of 41.2 MMcf per day and gross estimated recoverable reserves of 23.1 Bcf of proved natural gas, according to our independent reservoir engineering consultants. Proved reserves attributable to the Belin #1 are roughly two and one-half times the average size of our last five Bossier wells. The LOR #7 was drilled and subsequently successfully side-tracked after encountering thinner middle Bossier sands than expected in the original hole. The well encountered two middle Bossier zones and one upper Bossier zone and was completed only in the deepest zone. We plan to simulate the well in the remaining zones once natural gas prices improve.

As a result of our activity in East Texas, the field’s average production increased 25% from the third to the fourth quarter of 2008 and is expected to increase sequentially by over 38% in the first quarter of 2009. Currently, we are drilling one lower Bossier well, the Wildman #5, which should be completed in the second quarter of 2009. We have developed a considerable inventory of offset locations to our earlier successes in the Hilltop area; however, based on current industry and capital markets conditions, we are delaying further drilling until the environment improves.

In the Marcellus Shale we hold approximately 42,000 net acres in northern West Virginia and southwestern Pennsylvania. To date, we have drilled 10 shallow wells, which will allow us to hold the related leases with production. Currently, we are seeking a joint venture partner to help us further develop this play. We do not expect to drill additional shallow wells until we secure a joint venture partner or until natural gas prices improve. We will continue to maintain our leases through renewals, extensions and renegotiations of drilling commitments.

In New South Wales, Australia, the PEL 238 development project achieved substantial success in 2008, as we more than doubled our net 2P, or “proved plus probable” reserve certification to 119.4 Bcf from 57.0 Bcf in 2007. Prior to mid-year 2009, we expect to achieve first commercial production, which should enable us to move a portion of our “certified” reserves into the “proved” category, as recognized by the U.S. Securities and Exchange Commission, in our 2009 reserve report.

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We continued a coring program designed to evaluate additional CBM potential on PEL 238 with successful results. Through the drilling of seven core holes, we have identified areas containing thick, permeable, gas-bearing coals that cover substantial geographic areas and that should provide the basis for achieving our previously stated 2P reserve certification targets.

J. Russell Porter, Gastar’s Chairman, President and CEO, stated, “We are pleased with our operating results in 2008 and feel that our properties are performing in line with our expectations during the first quarter of 2009. Even with the downward revisions in reserves due to lower prices, we achieved a 16% increase in proved reserves and replaced over 200% of our production. This is due to the substantial success we achieved with the drill bit in East Texas and the extensive number of high potential offset locations that we have identified in the East Texas field. Even at current natural gas prices, we expect our lower Bossier development locations should generate attractive returns.

“In New South Wales, we further identified the quality and extent of the coal seam running through our acreage and have been highly encouraged by the results so far. We believe that the doubling of our 2P certified reserves is just the beginning of upcoming near-term reserve growth. Other industry players, including large multi-nationals, took significant interest in the region as we saw numerous coalbed methane M&A transactions near our acreage at increasingly higher asset values. Gastar and our partner are currently having discussions with other parties interested in joining our partnership, which would help finance the development of the CBM resource on PEL 238 and provide additional capital to the Company.

“We are continuing to seek a partner in our Marcellus Shale acreage. We have been very encouraged by the success of other operators in the play, and we are pleased to see that activity and industry interest has remained high, even when other areas are seeing a dramatic reduction in rig activity.

Our success is also driving increasing production volumes, as we expect first quarter 2009 production to average around 30 MMcfe per day - about 26% higher than in the fourth quarter. To mitigate some of our natural gas price risk, we currently have about 67% of our 2009 projected production hedged at a NYMEX average price of $5.62 per Mcf.”

Full-Year Results

For the year ended December 31, 2008, net income adjusted for impairments and unrealized hedging gains was $2.3 million, or $0.01 per share. Including a non-cash full-cost ceiling impairment of natural gas and oil properties of $14.2 million and an unrealized hedging gain of $6.5 million, reported net loss was $5.4 million, or $0.03 per share for 2008. This compares to an adjusted net loss of $19.9 million, or $0.10 per share for the year ended

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December 31, 2007. Including a gain on the sale of unproved natural gas and oil properties of $38.5 million, a non-cash full-cost ceiling impairment of natural gas and oil properties of $28.5 million, debt extinguishment expense of $15.7 million, a $1.4 million litigation settlement expense and $3.6 million of bad debt expense related to the litigation settlement, reported net loss was $30.5 million, or $0.15 per share, for 2007.

Net cash flows provided by operating activities for the year ended December 31, 2008 were $40.0 million, compared to $7.4 million for 2007. Net cash flows provided by operating activities, excluding the one-time items noted above, for the full-year 2008 were $40.0 million compared to $16.1 million for 2007.

Revenues for 2008 increased 83% to $63.2 million, compared to revenues of $34.6 million for 2007. Excluding unrealized gas hedge gain of $6.5 million, 2008 natural gas and oil revenues increased 64% to $56.7 million. The increase in natural gas and oil revenues was the result of higher natural gas production primarily in East Texas and a 28% increase in realized natural gas prices.

Average daily production for 2008 was 23.3 MMcfe, up 29% from 18.1 MMcfe for 2007. The average realized price for natural gas after hedging activities increased in 2008 to $6.63 per Mcf compared to $5.18 per Mcf in 2007. Natural gas prices per Mcf before the impact of realized gas hedges for 2008 averaged $6.92. We had no realized gas hedges in 2007.

Lease operating expenses were $7.6 million or $0.89 per Mcfe for the full-year 2008, versus $6.3 million or $0.95 per Mcfe in 2007. The total dollar increase was due to an increased number of Texas producing wells and related increased production. Per-unit LOE costs declined in Texas from $0.72 in 2007 to $0.71 in 2008. This decline is due to an $0.11 decrease in controllable well operations offset by a $0.10 increase related to ad valorem taxes and workover expense.

Liquidity and Capital Budget

As of December 31, 2008, we had cash and cash equivalents of $6.2 million and a net working capital deficit of approximately $157.2 million. Of this amount, $151.7 million was classified as the current portion of long-term debt, of which only $52.1 million is scheduled to mature during 2009. The current portion of the long-term debt scheduled to mature in 2009 is composed of $3.2 million of subordinated unsecured notes maturing between April and September 2009, $18.9 million of debt incurred under our revolving credit facility due October 15, 2009, and $30.0 million of convertible senior unsecured subordinated debentures due November 20, 2009. Amounts due under the revolving credit facility are subject to an automatic extension of maturity to December 10, 2010 if we demonstrate to the administrative agent our ability to repay or refinance all of the convertible senior unsecured

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subordinated debentures. Due to the lack of currently identifiable cash resources to repay indebtedness maturing in 2009 and the potential for acceleration of maturity as a result of cross default provisions, the $100.0 million 12 ³/4% senior secured notes are also included in current maturities, although they do not contractually mature until December 1, 2012. Debt maturities, covenants in existing debt agreements restricting the use of asset sale proceeds to retire the convertible senior unsecured subordinated debentures, current commodity price declines and the continuing equity and credit market crisis in the United States, among other factors, indicate that our ability to raise the cash necessary to retire our indebtedness may be more challenging than in ordinary economic times. Consequently, our independent registered public accounting firm has issued an opinion stating that the consolidated financial statements were prepared assuming we will continue as a going concern and further states that our need to refinance or raise capital to retire debt maturing in 2009 raises substantial doubt about our ability to continue as a going concern.

In light of the current market environment and the upcoming debt maturities, we have decreased our 2009 capital budget by $62.5 million from 2008 actual expenditures. Capital expenditures for 2009 are projected to be $71.2 million, consisting of $19.1 million in East Texas, $4.9 million in Appalachia, $24.3 million in New South Wales, $2.8 million in the Powder River Basin and other capital costs, and an additional $20.1 million for capitalized interest cost.

Based on our revised capital plan, our current cash on hand and internally generated cash flow, we project that over the next 12 months we will need to raise an additional $95.0 million to fund our exploration and development activities, working capital needs and meet the $52.1 million in scheduled debt maturities in 2009.

Management of the Company is currently pursuing various opportunities in order to generate the liquidity necessary to repay or refinance the obligations that are maturing in 2009, including the sale or partial sale of certain assets, solicitation of joint venture partners to reduce capital costs, general cost reductions, potential issuance of additional debt and the issuance of common equity. If we are not successful in raising the additional capital required for our current plan, we may further reduce our drilling and development program. As the operator of our East Texas and Marcellus Shale properties, a portion of our 2009 budget can be reduced, postponed or eliminated at our discretion or without substantial penalty under non-consent clauses applicable to joint exploration and development arrangements. There can be no assurance that the actions undertaken by the Company will result in a capital generating transaction or that any such transaction, if consummated, will generate net cash proceeds sufficient to repay or refinance all of the Company’s current maturities in 2009. The consolidated financial statements do not include any adjustments that might result from the outcome of uncertainty regarding the Company’s ability to raise additional capital, sell assets, or otherwise obtain sufficient funds to meet its current long-term debt obligations in 2009.

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Gastar Exploration Conference Call

Gastar Exploration’s management team will hold a conference call on March 17, 2009, at 10:00 a.m. Eastern Time (9:00 a.m. Central Time), to discuss these results. To participate in the call, dial (303) 262-2161 at least 10 minutes early and ask for the Gastar Exploration conference call. A replay will be available approximately two hours after the call ends and will be accessible until March 24. To access the replay, dial (303) 590-3000 and enter the pass code11127098#.

The call will also be webcast live over the Internet at www.gastar.com. To listen to the live call on the Web, please visit Gastar’s Web site at least 10 minutes early to register and download any necessary audio software. An archive will be available shortly after the call. For more information, please contact Donna Washburn at DRG&E at (713) 529-6600 or e-mail dmw@drg-e.com.

About Gastar Exploration

Gastar Exploration Ltd. is an exploration and production company focused on finding and developing natural gas assets in North America and Australia. The Company pursues a strategy combining deep natural gas exploration and development with lower risk CBM and shale resource development. The Company owns and operates exploration and development acreage in the deep Bossier gas play of East Texas and Marcellus Shale play in West Virginia and Pennsylvania. Gastar’s CBM activities are conducted within the Powder River Basin of Wyoming and concentrated on more than 6.0 million gross acres controlled by Gastar and its joint development partners in Australia’s Gunnedah Basin (PEL 238, PEL 433 and PEL 434) located in New South Wales.

Safe Harbor Statement and Disclaimer

This news release includes “forward looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. A statement identified by the words “may”, “expects”, “projects”, “anticipates”, “plans”, “believes”, “estimate”, “will”, “should” and certain of the other foregoing statements may be deemed forward-looking statements. Although Gastar believes that the expectations reflected in such forward-looking statements are reasonable, these statements involve risks and uncertainties that may cause actual future activities and results to be materially different from those suggested or described in this news release. These include risks inherent in the drilling of natural gas and oil wells, including risks of fire, explosion, blowouts, pipe failure, casing collapse, unusual or unexpected formation pressures, environmental hazards, and other operating and production risks inherent in the natural gas and oil drilling and production activities, which may temporarily or permanently reduce production or cause initial production or test results to not be indicative of future well performance or delay the timing of sales or completion of drilling operations, risks with respect to natural gas and oil prices, a material decline in which could cause Gastar to delay

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or suspend planned drilling operations or reduce production levels, risks relating to the receipt of a “going concern” statement in our auditor’s report on our 2008 consolidated financial statements, and risks relating to the availability of capital to fund drilling operations that can be adversely affected by adverse drilling results, production declines and declines in natural gas and oil prices and other risk factors described in Gastar’s Annual Report on Form 10-K and other filings with the SEC at www.sec.gov and on the System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com.

The SEC has generally permitted oil and gas companies in their filings with the SEC to disclose only proved reserves that under SEC definitions and guidelines a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. This news release discloses proved reserves that do not meet SEC definitions and guidelines and “probable” reserves along with “contingent resources” that the SEC’s guidelines would prohibit us from including in our filings with the SEC. All of these volumes and estimates are by their nature more speculative than estimates of proved reserves under SEC definitions and guidelines and accordingly are subject to substantially greater risk of being actually realized.

The NYSE Alternext US LLC and Toronto Stock Exchange have not reviewed and do not

accept responsibility for the adequacy or accuracy of this release.

- Financial Tables Follow -

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Three Months Ended						For the Year Ended
	12/31/08			12/31/07			12/31/08			12/31/07
REVENUES:
Natural gas and oil revenues	$	11,495		$	9,319		$	56,690		$	34,565
Unrealized natural gas hedge		5,023			—			6,529			—
Total revenues		16,518			9,319			63,219			34,565
EXPENSES:
Production taxes		241			(5	)		1,324			765
Lease operating expense		1,698			1,375			7,567			6,284
Transportation and treating		527			553			2,002			1,641
Depreciation, depletion and amortization		6,085			5,047			24,451			21,456
Impairment of natural gas and oil properties		14,217			—			14,217			28,514
Accretion on asset retirement obligation		85			66			335			281
Mineral resource properties		—			(25	)		—			(133	)
General and administrative expense		2,770			3,402			14,299			16,906
Litigation settlement expense		—			—			—			1,365
Total expenses		25,623			10,413			64,195			77,079
LOSS FROM OPERATIONS		(9,105	)		(1,094	)		(976	)		(42,514	)
OTHER (EXPENSE) INCOME:
Interest expense		(955	)		(2,298	)		(5,853	)		(14,079	)
Early extinguishment of debt		—			(15,684	)		—			(15,684	)
Investment income and other		75			977			1,542			3,196
Gain on sale of assets		—			(336	)		—			38,536
Foreign transaction gain (loss)		(15	)		(4	)		(74	)		5
LOSS BEFORE INCOME TAXES		(10,000	)		(18,439	)		(5,361	)		(30,540	)
Provision for income taxes		—			—			—			—
NET LOSS	$	(10,000	)	$	(18,439	)	$	(5,361	)	$	(30,540	)
NET LOSS PER SHARE:
Basic and diluted	$	(0.05	)	$	(0.09	)	$	(0.03	)	$	(0.15	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic and diluted		207,098,570			207,098,570			207,098,570			202,828,792

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

	As of December 31,
	2008		2007
	(in thousands)
Current Assets:
Cash and cash equivalents	$	6,153	$	85,854
Other		18,386		6,967
Total current assets		24,539		92,821
Property, plant and equipment, net		252,527		157,120
Total other assets		11,371		11,809
Total assets	$	288,437	$	261,750
LIABILITIES AND SHAREHOLDERS’ EQUITY
Total current liabilities	$	181,760	$	29,405
Long-term debt, net of current maturities		—		132,685
Other long-term liabilities		5,095		4,391
Total shareholders’ equity		101,582		95,269
Total liabilities and shareholders’ equity	$	288,437	$	261,750

PRODUCTION AND PRICES

	For Three Months Ended December 31,				For the Year Ended December 31,
	2008		2007		2008		2007
Production:
Natural gas (MMcf)		2,192		1,880		8,482		6,577
Oil (MBbl)		1		1		5		7
Total (MMcfe)		2,196		1,885		8,510		6,621
Natural gas (MMcfd)		23.8		20.4		23.2		18.0
Oil (MBod)		0.0		0.0		0.0		0.1
Total (MMcfed)		23.9		20.5		23.3		18.1
Average sales prices before hedging activity:
Natural gas (per Mcf)	$	4.77	$	4.91	$	6.92	$	5.18
Oil (per Bbl)	$	60.82	$	103.98	$	98.39	$	66.17
Average sales prices after hedging activity:
Natural gas (per Mcf) (1)	$	5.23	$	4.91	$	6.63	$	5.18
Oil (per Bbl)	$	60.82	$	103.98	$	98.39	$	66.17

(1) We had no hedging instruments on 2007 natural gas volumes.

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CURRENT HEDGE POSITION

The following derivative transactions were outstanding with associated notional volumes and hedge prices for the index specified as of February 20, 2009:

Date	Period	Derivative Instrument (1)	Notional Daily Volume	Notional Volume Remaining (2)	Base Fixed Price		Puts		Calls		Index	Production Area Hedged
			(MMBtu)	(MMBtu)			(MMBtu)		(MMBtu)
01/29/09	Cal 09	P	15,673	4,785,938		—	$	5.00		—	Nymex-HH	TX
10/15/08	Cal 09	CC	5,000	1,530,000		—	$	8.00	$	12.05	Nymex-HH	TX
10/15/08	Cal 09	I	5,000	1,530,000		—		—		—	GDD HSC (3)	TX
10/15/08	Cal 09	B	5,000	1,530,000	-$	0.3800		—		—	HSC (3)	TX
02/12/09	Cal 09	B	2,000	612,000	-$	0.3700		—		—	HSC (3)	TX
11/14/08	Cal 09	B	1,500	459,000	-$	2.2200		—		—	CIG (4)	WY
11/21/08	Cal 09	B	1,000	306,000	-$	2.0200		—		—	CIG (4)	WY
02/12/09	Cal 09	B	850	260,100	-$	1.7500		—		—	CIG (4)	WY

(1) CC = Costless collars.

(1) B = Basis swaps.

(1) I = Index swaps: Gas Daily to IFERC Monthly Index.

(1) P = Puts purchased.

(1) (P) = Puts sold.

(2) Notional volumes from 03/01/09.

(3) East-Houston-Katy – Houston Ship Channel.

(4) Inside FERC Colorado Interstate Gas, Rocky Mountains.

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