8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): November 9, 2007 (November 9, 2007)

GASTAR EXPLORATION LTD.

(Exact Name of Registrant as Specified in Its Charter)

ALBERTA, CANADA	001-32714	38-3324634
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

1331 LAMAR STREET, SUITE 1080

HOUSTON, TEXAS 77010

(Address of principal executive offices)

(713) 739-1800

(Registrant’s telephone number, including area code)

N/A

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

SECTION 7 – REGULATION FD

ITEM 7.01 REGULATION FD DISCLOSURE

On November 9, 2007, Gastar Exploration Ltd. (the “Company”) issued a press release announcing a proposed financing by its wholly owned subsidiary, Gastar Exploration USA, Inc. The Company also announced that the net proceeds of the offering will be used to repay existing indebtedness and for general corporate purposes.

Exhibit 99.1, which is incorporated by reference into this Item 7.01, sets forth certain supplemental information contained in the preliminary offering circular dated November 8, 2007 distributed to certain potential investors in connection with the proposed financing. Unless otherwise noted herein, as used in Exhibit 99.1 (i) “Company,” “Gastar,” “we,” “us,” or “our” refer to Gastar Exploration USA, Inc., the issuer of the notes, the Parent and its subsidiaries on a consolidated basis, (ii) “Parent” refers to Gastar Exploration Ltd., the parent of Gastar Exploration USA, Inc. only and not its subsidiaries, and (iii) “Issuer” refers to Gastar Exploration USA, Inc. only and not its Parent or subsidiaries.

The information contained in this Current Report on Form 8-K is neither an offer to sell nor a solicitation of an offer to buy securities. The securities have not been registered under the Securities Act of 1933, as amended, or the securities laws of any other jurisdiction and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements.

In accordance with General Instruction B.2 of Form 8-K, the information set forth in this Item 7.01 shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, nor shall such information be deemed incorporated by reference in such a filing. The information set forth in this Item 7.01 shall not be deemed an admission as to the materiality of any information in this report on Form 8-K that is required to be disclosed solely to satisfy the requirements of Regulation FD.

SECTION 8 – OTHER EVENTS

ITEM 8.01 – OTHER EVENTS

In connection with Gastar Exploration USA, Inc.’s proposed financing, the preliminary offering circular dated November 8, 2007 included a section entitled “GeoStar Look Back Developments.” A copy of “GeoStar Look Back Developments” is being filed as an Exhibit 99.2 to this report on Form 8-K and is being incorporated by reference in this Item 8.01.

SECTION 9 – FINANCIAL STATEMENTS AND EXHIBITS

ITEM 9.01 FINANCIAL STATEMENTS AND EXHIBITS

(d) Exhibits

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The following is a list of exhibits furnished or filed, as specified, as part of this Form 8-K:

Exhibit No.	Description of Document
99.1	Supplemental information (furnished in accordance with General Instruction B.2 of Form 8-K)
99.2	GeoStar Look Back Developments

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

		GASTAR EXPLORATION LTD.
Date: November 9, 2007	By:	/s/ J. RUSSELL PORTER
		J. Russell Porter
		President and Chief Executive Officer

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EXHIBIT INDEX

Exhibit No.	Description of Document
99.1	Supplemental information (furnished in accordance with General Instruction B.2 of Form 8-K)
99.2	GeoStar Look Back Developments

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EX-99.1

Exhibit 99.1

ASSET OVERVIEW

	(dollars in thousands)
Reserve Data as of June 30, 2007:
PV-10—SEC Case(1)	$	76,947
PV-10—Natural Gas Forward Pricing Case(2)		110,081
Other Data as of September 30, 2007:
Cash(3)	$	101,121
Estimated Future Capital Costs to Develop Proved Reserves(4)		(38,324)
Unproved properties, not being amortized (book value):
United States	$	44,679
Australia		22,089
Domestic Asset Overview:
Net acreage—East Texas		16,500
East Texas—Deep Bossier Data:
Identified Gross Drilling Locations		115
Number of Producing Wells Drilled in 2006-2007		13
Average Net Estimated Ultimate Recovery (“EUR”)(5) Per Well Drilled in 2006-2007 (Bcfe)		2.3
Range of Drilling Depth (ft.)		16,500-19,500
Average Days Drilling		110
Average Days for Completion		30
East Texas—Knowles Limestone Data:
Identified Gross Drilling Locations		20
Number of Producing Wells Drilled in 2006-2007		3
Average Net Estimated Ultimate Recovery (“EUR”)(5) Per Well Drilled in 2006-2007 (Bcfe)		0.7
Range of Drilling Depth (True Vertical Depth, ft.)		13,500-14,000
Average Days Drilling		60
Average Days for Completion		20
International Asset Overview:
PEL 238 Data:
Net Acreage		786,000
Estimated Economic Net Acreage with Identified SPE Definition Proved Reserves		490
Identified Net Proved Reserves—SPE Definition (Bcfe)(6)		6.6
Gastar Interest in PEL 238		35.0%
Eastern Star Gas Limited Interest in PEL 238		65.0%

⁽¹⁾ Based on constant natural gas and oil pricing and costs in effect as of June 30, 2007 per SEC guidelines.

⁽²⁾ Present value discounted at 10% of future net revenues of proved reserves at June 30, 2007 using constant pricing based upon the October 24, 2007 average NYMEX forward natural gas sale pricing of $8.00 per MMBtu for calendar year 2008 and constant oil pricing and costs as of June 30, 2007. See “Gas Price Sensitivities—Forward Pricing Sensitivities” on page 19 for a further description of pricing assumptions.

⁽³⁾ As adjusted to give effect to this offering. See “Capitalization” on page 42.

⁽⁴⁾ Based on the reserve report of Netherland Sewell as of June 30, 2007 (the “June 30 Report”).

⁽⁵⁾ Cumulative production to June 30, 2007 plus proved reserves estimated in the June 30 Report.

⁽⁶⁾ Based on estimates as of September 1, 2007 of Netherland Sewell prepared using SPE definitions and guidelines for proved reserves. Reserves are not proved reserves under SEC definitions and guidelines.

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RECENT DRILLING ACTIVITY

Since the end of 2005, we have drilled 10 wells in East Texas with a 100% success rate. We recently acquired a 3-D seismic survey, developed and planned jointly with Chesapeake Energy Corporation (“Chesapeake”), that covers 100% of our East Texas acreage, which provides additional information critical to refine our geologic and geophysical models for the deep Bossier and Knowles Limestone formations. We seek to capitalize on this data to improve the likelihood of repeating the recent successes we have had in our most recent deep Bossier and Knowles Limestone wells. Our last deep Bossier and Knowles Limestone wells drilled in the Hilltop area have estimated ultimate recoveries (“EURs”) of approximately 10.9 gross Bcfe (5.5 net Bcfe) and 1.8 gross Bcfe (0.7 net Bcfe) and cost $12.6 million gross and $6.8 million gross to drill and complete, respectively. We have identified 6 gross (4 net) additional deep Bossier locations directly offsetting the Donelson #3 well that represent approximately a two year drilling inventory. Further upside potential exists on our East Texas acreage through the exploitation of reserve potential in the Knowles Limestone formation. We believe we are the first company to establish commercial production in the Knowles Limestone formation in East Texas. We have drilled three wells with a 100% success rate in this formation and are in the process of drilling a fourth well. Wells drilled in the Knowles Limestone are characterized by lower drilling costs than the deep Bossier wells and a shorter drilling and completion cycle, with individual wells taking approximately 80 days from spud to sales.

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INDEPENDENT ENGINEERING ESTIMATES

The estimates of our proved reserves and their present value are from the reserve report of Netherland Sewell as of June 30, 2007 using SEC pricing as of June 30, 2007.

	Reserve Category
	PDP		PDNP		PUD		Total
Net reserves:
Natural gas (MMcf)		14,916		9,625		11,795		36,336
Oil (MBbls)		15		—		—		15
Future net revenues (000’s):
Natural gas	$	86,085	$	54,668	$	66,903	$	207,656
Oil		1,017		—		—		1,017
Total revenues	$	87,102	$	54,668	$	66,903	$	208,673
Production and ad valorem taxes		4,210		2,616		3,239		10,065
Operating expense		30,390		8,198		15,576		54,164
Capital costs		2,358		4,971		30,995		38,324
Future net revenues	$	50,144	$	38,883	$	17,093	$	106,120
Future net revenues discounted at 10% (“PV-10”)	$	40,585	$	28,805	$	7,557	$	76,947

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SUMMARY RESERVE AND PRODUCTION DATA

The following table summarizes our estimates of our domestic net proved natural gas and oil reserves and the present value attributable to the reserves as of June 30, 2007 (using SEC prices as of June 30, 2007 and NYMEX prices as of October 24, 2007), discounted at 10% per annum. Estimates of our net proved natural gas and oil reserves at June 30, 2007 were prepared by Netherland, Sewell & Associates, Inc., our independent petroleum engineers.

	As of June 30, 2007
Proved Reserves:
Natural gas (MMcf)		36,336
Oil and condensate (MBbls)		15
Natural gas equivalent (MMcfe)		36,425
Proved developed reserves		67.6	%
PV-10(1) (SEC Case)(000’s)	$	76,947
PV-10(2) (Natural Gas Forward Pricing Case)(000’s)	$	110,081
Reserve life index (in years)(3)		7.1

⁽¹⁾ Present value discounted at 10% of future net revenues of proved reserves at June 30, 2007 using constant pricing and costs in accordance with SEC guidelines.

⁽²⁾ Present value discounted at 10% of future net revenues of proved reserves at June 30, 2007 using constant pricing based upon the October 24, 2007 average calendar year 2008 NYMEX forward natural gas sale pricing of $8.00 per MMBtu and constant oil pricing and costs as of June 30, 2007. See “Natural Gas Pricing Sensitivities” on page 17 for a further description of pricing assumptions.

⁽³⁾ Calculated by dividing net proved reserves by net production volumes for the 12-month period ended June 30, 2007.

The following table summarizes our net production volumes, natural gas and oil sales, and average sales prices for the periods indicated:

	Year ended December 31,						Nine months ended September 30,
	2004		2005		2006		2006		2007
Net production volumes:
Natural gas (MMcf)		1,108		3,810		4,646		3,411		4,696
Oil (MBbls)		2		2		12		8		7
Combined (MMcfe)		1,119		3,821		4,716		3,457		4,736
Natural gas and oil sales (000’s):
Natural gas	$	5,987	$	27,345	$	26,014	$	19,457	$	24,842
Oil		72		97		751		531		404
Total	$	6,059	$	27,442	$	26,765	$	19,988	$	25,246
Average sales prices:
Natural gas (per Mcf)	$	5.40	$	7.18	$	5.60	$	5.70	$	5.29
Oil and condensate (per Bbl)		40.08		50.85		64.66		68.19		61.01
Lease operating, transportation and selling expenses taxes (per Mcfe)		1.78		1.81		1.82		1.92		1.43

PV-10 of proved reserves (SEC case) is not a substitute for the standardized measure of discounted future net cash flows, which is calculated at year end under accounting rules. Our PV-10 measures and the standardized measure of discounted future net cash flows do not purport to present the fair value of our natural gas and oil reserves.

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NATURAL GAS PRICING SENSITIVITIES

The following are estimates of our future net revenues for the year ending December 31, 2008 and PV-10 of all future net revenues based on our proved reserves as of June 30, 2007 shown under SEC mandated constant pricing and at various alternate natural gas pricing scenarios. Estimates of production, costs and expenses are derived from our reserve report dated June 30, 2007 prepared by Netherland Sewell (the “June 30 Report”). The June 30 Report was prepared using constant oil and gas pricing and costs in effect on June 30, 2007, in accordance with the guidelines of the Securities and Exchange Commission.

In order to demonstrate the effects of natural gas pricing changes on our estimates of future net revenues from proved reserves and PV-10 values of such future net revenues, we have prepared estimates of future net revenues and PV-10 using assumed natural gas prices that are 20 and 10 percent higher and 20 and 10 percent lower than the June 30, 2007 spot market gas prices utilized in the June 30 Report. Gas prices used in the June 30 Report were based on Henry Hub spot market price of $6.795 per MMbtu for Texas and Kansas production; Colorado Interstate Gas (“CIG”) Rocky Mountains spot market price of $3.98 per MMBtu for Montana and Wyoming production; and Columbia Gas Appalachia spot market price of $7.28 per MMbtu for West Virginia production. Appropriate adjustments were made to these prices for quality, transportation and other infield price adjustments. In each case, oil prices were held constant based on the June 30, 2007 West Texas Intermediate posted price of $67.25 per barrel.

Future production will vary from the estimates in the June 30 Report when different pricing assumptions are made due to changes in economic limits of production, which primarily affects our Montana and Wyoming reserves. Actual production from properties with proved reserves may vary significantly from those estimated in the June 30 Report or in the other pricing cases reflected in this analysis, which will affect actual net revenues received in the indicated year.

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PV-10 Gas Pricing Sensitivities

	As of June 30, 2007
	June 30 Gas Prices Minus 20%		June 30 Gas Prices Minus 10%		June 30 Report SEC Constant Pricing		June 30 Gas Prices Plus 10%		June 30 Gas Prices Plus 20%
Average natural gas price ($/Mcf)	$	4.48	$	5.11	$	5.71	$	6.23	$	6.79
Average oil and condensate prices ($/Bbl)	$	68.29	$	68.30	$	68.30	$	68.29	$	68.30
PV-10 of future net revenues from proved reserves (000s)	$	47,985	$	61,902	$	76,947	$	92,579	$	108,601
Future Net Revenue Pricing Sensitivities
	Year Ending December 31, 2008
	June 30 Gas Prices Minus 20%		June 30 Gas Prices Minus 10%		June 30 Report SEC Constant Pricing		June 30 Gas Prices Plus 10%		June 30 Gas Prices Plus 20%
	(dollars in thousands, except per unit amounts)
Net oil and condensate production (MBbls)		4.0		4.1		4.2		4.2		4.3
Net natural gas production (MMcf)		5,912		8,423		8,789		9,078		9,173
Average natural gas price ($/Mcf)(1)	$	4.34	$	5.04	$	5.63	$	6.17	$	6.74
Average oil and condensate prices ($/Bbl)(2)		68.20		68.20		68.21		68.22		68.21
Future gross revenue natural gas	$	25,691	$	42,473	$	49,492	$	55,975	$	61,809
Future gross revenue oil and condensate		274		280		285		288		291
Future gross revenue total		25,965		42,753		49,777		56,263		62,100
Production and ad valorem taxes		1,286		1,942		2,273		2,657		2,960
Operating expenses		7,066		8,805		9,212		9,695		9,900
Capital costs(3)		2,063		16,016		23,039		23,550		23,954
Future net revenues from proved reserves	$	15,550	$	15,990	$	15,253	$	20,361	$	25,286

⁽¹⁾ Weighted average of gas price for estimated production after adjustments for delivery point differentials, energy content, quality, transportation and other infield price adjustments.

⁽²⁾ West Texas Intermediate oil prices posted price as of June 30, 2007.

⁽³⁾ Substantially all capital costs are incurred in the drilling of proved undeveloped reserves.

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Forward Pricing Sensitivities

At October 24, 2007, the average of NYMEX forward sale natural gas price for Henry Hub deliveries for the twelve months in the calendar year 2008 was $8.00 per MMBtu, and the average of the monthly basis differentials for CIG Rocky Mountains forward deliveries in 2008 from NYMEX was $1.50 per MMBtu, as quoted to us by derivatives traders at a major investment bank. After applying these natural gas pricing and Rocky Mountains differential assumptions on a constant basis, holding oil prices and costs constant at the prices and costs reflected in the June 30 Report and further adjusting the differential for natural gas prices received for our estimated Rocky Mountains (Wyoming and Montana) production in the second half of 2007 to reflect monthly actual and forward delivery discounts for CIG Rocky Mountains, our estimated proved reserves, future net revenues from our proved reserves and related PV-10 – Natural Gas Forward Pricing Case as of June 30, 2007 would have been as set forth in the table as below.

	Reserve Category
	PDP		PDNP		PUD		Total
Net proved reserves:
Natural gas (MMcf)		15,908		9,662		17,851		43,421
Oil (MBbls)		16		—		—		16
Future net revenues (000’s):
Natural gas	$	107,787	$	67,565	$	120,347	$	295,699
Oil		1,085		—		—		1,085
Total revenues	$	108,872	$	67,565	$	120,347	$	296,784
Production and ad valorem taxes		5,783		3,485		9,025		18,293
Operating expense		35,705		9,082		30,075		74,862
Capital costs		2,378		4,971		41,679		49,029
Future net revenues	$	65,006	$	50,027	$	39,568	$	154,600
PV-10—Natural Gas Forward Pricing Case	$	51,441	$	37,014	$	21,626	$	110,081

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EX-99.2

Exhibit 99.2

GEOSTAR LOOK BACK DEVELOPMENTS

The Purchase and Sale Agreements between GeoStar and the Company relating to certain East Texas properties acquired by the Company in 2005 (the “PSAs”) contain a “Look Back” provision that is the subject of claims in two of the previously described lawsuits with GeoStar. Under that provision, two “Look Back Payments” are to be calculated based on changes in proved and probable reserves attributable to certain of the Company’s leasehold interests over certain periods of time ending June 30, 2006 and 2007. If a Look Back Payment is due to GeoStar under the PSAs, the PSAs require the payment to be effected through the issuance of our Parent company’s stock. The PSAs provide that the calculation of the Look Back Payment shall be based upon reserve estimates reported by Netherland Sewell & Associates, Inc. (“NSA”), or in certain circumstances, based upon an average of the NSA estimates and estimates obtained by GeoStar from an independent, professionally certified reservoir engineering firm utilizing the same regulatory requirements and reserve calculation guidelines as those employed by NSA in its estimates.

On November 1, 2007, GeoStar informed the board of directors of our Parent that it intended to submit a reserve report for purposes of the June 30, 2006 and 2007 Look Back analyses showing that the gross reserves attributable to the Company’s leasehold interests are substantially greater than those reflected in the NSA reserve reports on which the Company’s Look Back analyses were based. On November 7, 2007, GeoStar submitted a reserve report to the Company that reported a substantially greater reserve estimate than the estimates in the NSA reserve report. The terms of the PSAs provide that, under certain circumstances, the Look Back Payments will be determined based on a formula using the average of the proved and probable reserve estimates made in the NSA report and an independent report obtained by GeoStar. The Company believes that the alternative reserve report submitted by GeoStar does not meet the requirements of the PSAs because, among other things, the GeoStar report (i) provides reserve estimates on a full 8/8ths interest basis rather than based on the undivided interests that the Company contends were the subject of the PSA transaction and (ii) did not utilize the same regulatory requirements and reserve calculation guidelines employed by NSA as required per the terms of the PSAs. GeoStar has asserted that the Look Back analysis should be based on changes in reserves attributable to the entirety, or 8/8ths, of the leasehold interests with respect to the East Texas properties, rather than on changes in reserves attributable to GeoStar’s net revenue interest in those properties as of the effectiveness of the PSAs, as the Company believes.

The Company believes that GeoStar’s assertions are without merit and is in the process of reviewing the GeoStar reserves report, GeoStar’s contentions relating thereto, and the Company’s legal position and options. However, an unfavorable outcome in litigation relating to the Look Back could have a material adverse effect on the Company because of the substantial disparities (i) between the NSA reserves estimate and the current GeoStar reserves estimate that GeoStar may contend should be averaged with the NSA estimate for purposes of the Look Back analysis, and (ii) between GeoStar’s assertion as to the portion of the Company’s East Texas leasehold interests subject to the Look Back analysis and the Company’s belief as to that issue. If GeoStar were to present both of these current assertions in litigation and obtain an outcome adverse to the Company on both issues, our Parent could be required to issue a number of shares to GeoStar sufficient to cause a change in control of ownership of our Parent. The Company intends to vigorously defend itself against any such claims GeoStar may assert.

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