Edgar Filing: GASTAR EXPLORATION LTD

Form S-1

Index to Financial Statements

As filed with the Securities and Exchange Commission on August 12, 2005

Registration No. 333-

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

GASTAR EXPLORATION LTD.

(Exact Name of Registrant as Specified in Its Charter)

Alberta, Canada

1311

38-3324634

(State or Other Jurisdiction of

Incorporation or Organization)

(Primary Standard Industrial

Classification Code Number)

(I.R.S. Employer

Identification Number)

1331 Lamar Street

Suite 1080

Houston, Texas 77010

(713) 739-1800

(Address, Including Zip Code, and Telephone Number, including Area Code, of Registrant’s Principal Executive Offices)

J. Russell Porter, Chief Executive Officer and President

Gastar Exploration Ltd.

1331 Lamar Street, Suite 1080

Houston, Texas 77010

(713) 739-1800

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

Copies to:

T. Mark Kelly

Vinson & Elkins L.L.P.

1001 Fannin, Suite 2300

Houston, Texas 77002

(713) 758-2222

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. x

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. ¨

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered

Amount to be
Registered (1)

Proposed Maximum
Offering Price

per Share (2)

Proposed Maximum
Aggregate

Offering Price (1) (2)

Amount of
Registration
Fee

Common shares, without par value

24,022,444 shares

$2.60

$62,458,354

$7,400.00

(1)

Includes (i) 4,997,288 common shares issuable upon exercise of warrants at various exercise prices; (ii) 6,849,315 common shares to be issued upon conversion of the registrant’s outstanding convertible debentures; (iii) up to 4,340,836 additional common shares to be issued at various dates for no additional consideration pursuant to the terms of the original sale of the registrant’s senior secured notes (number of shares determined based upon a recent trading price of CND$3.11 per share); and (iv) 7,835,005 outstanding common shares.

(2)

Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(c) under the Securities Act of 1933 based on the average of the high and low prices of the Registrant’s common shares, as reported on The Toronto Stock Exchange on August 10, 2005, and translated into U.S. dollars at the exchange rate of $1.00 = CND$0.8256, which was the exchange rate in effect on August 10, 2005.

The Registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment that specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission acting pursuant to said Section 8(a), may determine.

Index to Financial Statements

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion, dated August 12, 2005

PROSPECTUS

[Logo]

24,022,444 Shares

Gastar Exploration Ltd.

Common Shares

This prospectus relates to the offer and sale, from time to time, of up to 24,022,444 common shares of Gastar Exploration Ltd., an Alberta corporation, held by or issuable to the selling shareholders listed on page 62 of this prospectus. The common shares being offered by the selling shareholders are outstanding, issuable upon conversion of the convertible debentures, issuable pursuant to outstanding subscription receipts and upon exercise of warrants. See “Selling Shareholders”. Gastar will not receive any proceeds from the sale of the shares by the selling shareholders. All the proceeds from the sale of shares will be for the respective account of each selling shareholder.

For a description of the plan of distribution of the shares, please see page 66 of this prospectus.

Our common shares are listed on the Toronto Stock Exchange under the symbol “YGA” (in the U.S., “YGA.TO”) and may also trade in the United States over-the-counter market under the symbol “GSREF.PK”. On August 5, 2005, the last reported sale prices for our common shares on The Toronto Stock Exchange and in the U.S. on the OTC Bulletin Board were CDN$3.11 and $2.56, respectively.

Investing in our common shares involves risks. Please read “ Risk Factors” beginning on page 6.

This prospectus has not been filed in respect of, and will not qualify, any distribution of the common shares in any province or territory of Canada.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

, 2005

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TABLE OF CONTENTS


Prospectus Summary		1
The Offering		4
Summary Consolidated Financial Data		5
Risk Factors		6
Cautionary Statements Regarding Forward-Looking Statements		17
Use of Proceeds		18
Price Range of Common Shares		18
Dividend History		19
Selected Historical Financial and Operational Information		20
Management’s Discussion and Analysis of Financial Condition and Results of Operations		21
Business		33
Management		56
Security Ownership of Certain Beneficial Owners and Management		62
Description of Capital Stock		64
Description of Indebtedness		69
Selling Shareholders		71
Plan of Distribution		75
Certain Relationships and Related Party Transactions		78
Material Income Tax Consequences		80
Legal Matters		84
Experts		84
Where You Can Find More Information		85
Index to Financial Statements		F-1

Appendix A – Glossary of Natural Gas and Oil Terms		A-1

You should rely only on the information contained in this prospectus. We have not authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date.

Unless otherwise specified or the context otherwise requires, all dollar amounts in this prospectus are expressed in U.S. dollars. Canadian dollars, when used, are expressed with the symbol “CDN$”. Unless otherwise specified, where dollars are shown on a converted basis, the conversion is based upon an exchange ratio of $1.00 = CDN$0.8205, the exchange rate in effect on August 5, 2005, except for dollars set forth in or derived from the financial statements, where the exchange rate is derived as of the date of the financial statements.

Index to Financial Statements

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the detailed information contained under the heading “Risk Factors”, consolidated financial statements and the accompanying notes to those financial statements included elsewhere in this prospectus. Unless otherwise indicated or required by the context, (i) “we”, “us”, and “our” refer to Gastar Exploration Ltd. and its subsidiaries and predecessors, (ii) “Geostar acquisition” refers to our June 2005 acquisition from Geostar Corporation (“Geostar”) of additional reserves and working interests in the Powder River Basin and in East Texas, (iii) “convertible debentures” refers to our $30.0 million principal amount of 9.75% convertible senior unsecured debentures, (iv) “warrants” refers to the warrants to purchase common shares issued to investors in connection with certain financing transactions or to our placement agents in connection with the offering of convertible debentures and certain other subordinated notes as partial compensation for their services, (v) “senior secured notes” refers to our $63.0 million principal amount of senior secured notes issued in June 2005, (vi) all dollar amounts appearing in this prospectus are stated in U.S. dollars unless specifically noted in Canadian dollars (“CDN$”), and (vii) all financial data included in this prospectus has been prepared in accordance with generally accepted accounting principles in the United States. We have provided definitions for some of the natural gas and oil industry terms used in this prospectus in the “Glossary of Natural Gas and Oil Terms” on page A-1 of this prospectus.

Gastar Exploration Ltd.

Our Business

•

Deep Bossier play in East Texas;

•

Powder River Basin in Wyoming and Montana;

•

Gunnedah Basin in New South Wales, Australia;

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Gippsland Basin in Victoria, Australia;

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Appalachian Basin in West Virginia;

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San Joaquin Basin in California; and

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Cherokee Basin in Southeast Kansas.

We currently are pursuing conventional natural gas exploration in the Deep Bossier play in the Hilltop area in East Texas and the Appalachian Basin in West Virginia. In exploring for conventional hydrocarbons, we utilize advanced geophysics and geologic technologies to identify high potential natural gas prospects. As of June 30, 2005, we had leases on approximately 53,100 gross acres (34,000 net) in Texas and approximately 26,700 gross acres (13,300 net) in Appalachia. For the six months ended June 30, 2005, our daily net production from the Hilltop area averaged approximately 6.9 MMcfed, and from the Appalachian Basin, it averaged 0.1 MMcfed.

Index to Financial Statements

acreage position in the Powder River Basin was approximately 56,800 gross acres (21,900 net), and our Australian acreage totaled approximately 3.4 million gross acres (2.0 million net). For the six months ended June 30, 2005, our average net daily production from our CBM properties in the Powder River Basin was approximately 1.9 MMcfed. Exploration and long term production testing on our Australian CBM properties is currently underway. Thus, we currently have no natural gas sales from our Australian CBM properties.

Our Strategy

Management believes that:

•

Natural gas is an environmentally friendly fuel that will be increasingly valued in the United States and Australia;

•

Conventional natural gas exploration exposes us to potentially large natural gas reserves and significant increases in shareholder value;

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CBM projects provide us with lower risk exposure to long-lived natural gas production and reserves;

•

We have made a significant natural gas discovery in the Deep Bossier play in the Hilltop area of East Texas that will require additional exploration and development;

•

We have the ability to assemble the technical and commercial resources needed to pursue these potential projects; and

•

Our successful development of one or more large potential natural gas projects will create substantial shareholder value.

Based on these beliefs, we have pursued a strategy that includes:

•

Accelerating exploration and development drilling on our Deep Bossier play in East Texas;

•

Combining lower risk CBM projects, such as the Powder River Basin and Australia, with higher risk conventional natural gas exploration;

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Assembling a portfolio of high-potential natural gas exploration and development projects in East Texas and in the Appalachian Basin; and

•

Limiting capital commitments and reducing risk by maintaining financial flexibility through accessing various sources of capital and monetizing certain assets through joint venture arrangements with industry participants.

Recent Developments

Issuance of Senior Secured Notes and Common Shares. On June 17, 2005, we completed the private placement of $63.0 million in principal amount of senior secured notes and 1,217,269 common shares. The notes bear interest at three month LIBOR plus 6% and mature on June 18, 2010. We also committed to issue to the purchasers of the notes, for no additional consideration, common shares in CDN$4.5 million increments on each of the six, twelve and eighteen-month anniversaries of the original note issuance date valued on a five-day weighted average trading price immediately prior to the date of issuance.

Index to Financial Statements

the additional principal amount of the notes. To issue these additional notes, we must meet certain requirements, including a minimum ratio of our present value discounted at 10%, based on prices specified in the senior secured notes, of proved plus probable reserves to net senior secured debt.

Geostar Acquisition. Concurrently with the private placement of senior secured notes, we closed the acquisition of additional leasehold and working interest properties from Geostar in the Hilltop area of East Texas and in the Powder River Basin of Wyoming and Montana. We paid a total of $68.5 million for the interests acquired from Geostar consisting of $30.5 million in cash, 1,650,133 common shares valued at CDN$4.50 per share and $32.0 million in unsecured subordinated notes maturing on January 31, 2006. The acquisition increased our working interest position in the Hilltop area to an average of over 90% and gave us operational control of the properties. The acquisition of additional Powder River Basin interests provides us with a larger interest in properties currently being developed through an existing joint venture. The Board of Directors retained a qualified, independent investment banking firm to render an opinion regarding the fairness of the Geostar acquisition. The investment banking firm provided the Board of Directors with their opinion that the Geostar acquisition was fair for Gastar’s shareholders from a financial perspective.

On August 11, 2005, we executed an agreement with Geostar whereby the Geostar $32.0 million unsecured subordinated note was cancelled. In conjunction with the note cancellation, we agreed to issue Geostar $17.0 million of our common shares issued at a value of CDN$3.25 and a new unsecured subordinated note for $15.0 million. The new Geostar note bears interest, payable monthly commencing February 15, 2006, at three-month LIBOR plus 4.5% and matures November 15, 2006. The note requires monthly principal payments of $1.5 million commencing February 15, 2006 and continuing for nine months thereafter with a final principal payment of $1.5 million due on November 15, 2006. We may elect to pay interest in kind through the issuance of additional notes with such notes maturing on January 15, 2007.

Common Share Placement. On June 30, 2005, we completed a private placement of 6,617,736 common shares at CDN$3.31 per share. The estimated net proceeds from this placement were $16.4 million (CDN$20.5 million), after deducting placement fees and expenses.

Corporate Information

We are a Canadian corporation that is subsisting under the Business Corporations Act (Alberta). Our principal office is located at 1331 Lamar Street, Suite 1080, Houston, Texas 77010, and our telephone number is (713) 739-1800. Our website address is http://www.gastar.com. Information on our website or about us on any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

We were originally incorporated in 1987 under the name CopperQuest Inc. pursuant to the Business Corporations Act (Ontario). On May 16, 2000, we continued from the Province of Ontario into the Province of Alberta to subsist pursuant to the Business Corporations Act (Alberta), changed our name to Gastar Exploration Ltd. and, pursuant to a reverse takeover, acquired 1075191 Ontario Ltd. and its resource property in Wyoming. Our common shares were quoted on the Canadian Dealing Network Inc. and its successor, the Canadian Venture Exchange, from June 5, 2000 until January 24, 2002 when our common shares began trading on The Toronto Stock Exchange under the symbol “YGA” (in the U.S., “YGA.TO”).

Index to Financial Statements

THE OFFERING

Common shares to be offered by the selling shareholders shares

24,022,444

Use of proceeds

We will not receive any of the proceeds from the sale of the shares by the selling shareholders. All the proceeds from the sale of shares will be for the respective accounts of the selling shareholders.

Exchange listing

Our common shares are listed on the Toronto Stock Exchange under the symbol “YGA” (in the U.S., “YGA.TO”) and may be traded in the United States over-the-counter market under the symbol “GSREF.PK”.

This prospectus relates to the offer and sale, from time to time, of the common shares by selling shareholders. Pursuant to various agreements entered into in connection with the offering of our securities, we are required to register for resale certain of our common shares that are either now outstanding or will be issued upon exercise of certain warrants or conversion of our convertible debentures or common shares that we have issued, or committed to issue pursuant to subscription receipts. We are also offering the opportunity to participate in the registration statement to other holders of some of our restricted securities. Shares covered in the registration will include 7,835,005 outstanding common shares currently held by some holders and additional common shares to be issued in the future in connection with the following:

•

The exercise of outstanding warrants to purchase 4,997,288 common shares;

•

The conversion of our convertible debentures, which are convertible into 6,849,315 common shares; and

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The issuance of an estimated 4,340,836 common shares that we have committed to issue pursuant to subscription receipts on future dates for no additional consideration to purchasers of our senior secured notes.

For additional information about our warrants, see “Description of Capital Stock”. For additional information about our convertible debentures, our senior secured notes and the shares issuable in connection with our senior secured notes, see “Description of Indebtedness”.

Index to Financial Statements

SUMMARY CONSOLIDATED FINANCIAL DATA

The following table presents summary historical financial data as of and for the periods indicated. The summary consolidated financial data as of and for the years ended December 31, 2004, 2003 and 2002 are derived from our audited consolidated financial statements. The summary consolidated financial data as of March 31, 2005 and for the three months ended March 31, 2005 and 2004 are derived from our unaudited consolidated financial statements.

Our unaudited consolidated financial statements include, in the opinion of management, all adjustments, consisting only of normal, recurring adjustments, that management considers necessary for a fair statement of the results of those periods. Our historical results are not necessarily indicative of results to be expected in any future period and the results for the three months ended March 31, 2005 should not be considered indicative of results expected for the full 2005 fiscal year.

You should read the following summary consolidated financial data in conjunction with our audited and unaudited consolidated financial statements and the accompanying notes included elsewhere in this prospectus and the sections of this prospectus entitled, “Selected Historical Financial and Operational Information” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.


	As of and for the Three Months Ended March 31,						As of and for the Years Ended December 31,
	2005			2004			2004			2003			2002
	(Unaudited)
	(in thousands, except per share amounts)
Consolidated Statement of Loss Data:
Revenues	$	4,731		$	356		$	6,059		$	1,461		$	783
Operating loss before interest expense	$	(5,497	)	$	(242	)	$	(9,587	)	$	(2,368	)	$	(2,657	)
Net loss	$	(7,636	)	$	(670	)	$	(12,776	)	$	(4,947	)	$	(4,599	)
Basic and diluted loss per share	$	(0.07	)	$	(0.01	)	$	(0.12	)	$	(0.05	)	$	(0.05	)
Shares used in the calculation of basic and diluted loss per share		113,788			107,265			111,374			104,958			98,618

Consolidated Balance Sheet Data:
Net natural gas and oil properties	$	63,363					$	56,556		$	35,791		$	34,457
Long term liabilities	$	60,096					$	60,668		$	3,992		$	12,291
Total shareholders’ equity	$	15,157					$	21,976		$	23,669		$	22,430

Production Data:
Production:
Natural gas (MMcf)		849			83			1,108			385			393
Oil (MBbl)		0.7			0.0			1.8			1.0			3.1
Oil Natural gas equivalents (Mmcfe)		853			83			1,119			391			412

Natural gas (MMcfd)		9.4			0.9			3.0			1.1			1.1
Oil (MBod)		0.0			0.0			0.0			0.0			0.0
Oil Natural gas equivalents (Mmcfed)		9.5			0.9			3.1			1.1			1.1

Average Sales Prices:
Natural gas ($ per Mcf)	$	5.53		$	3.47		$	5.40		$	3.72		$	1.33
Oil ($ per Bbl)	$	48.80		$	31.13		$	40.08		$	27.89		$	20.15

Index to Financial Statements

RISK FACTORS

In addition to the other information set forth elsewhere in this prospectus, you should carefully consider the following factors when evaluating Gastar. An investment in Gastar will be subject to risks inherent in our business. The trading price of the common shares of Gastar will be affected by the performance of our business relative to, among other things, competition, market conditions and general economic and industry conditions. The value of an investment in Gastar may decrease, resulting in a loss. Additional risks and uncertainties not currently known to us or that we currently consider immaterial may also materially and adversely affect our business. The risk factors listed below are not all inclusive.

Risks Related to our Business

Our success depends on the market price for natural gas and oil.

The success of our business greatly depends on market prices of natural gas and oil. The higher market prices are, the more likely it is that we will be financially successful. On the other hand, declines in natural gas or oil prices may materially adversely affect our financial condition, profitability and liquidity. Lower prices also may reduce the amount of natural gas or oil that we can produce economically.

Natural gas and oil are commodities whose prices are set by broad market forces. Historically, the natural gas and oil markets have been volatile. We do not see any reason why natural gas or oil prices will not continue to be volatile in the future. Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas or oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include:

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The domestic and foreign supply of natural gas and oil;

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Overall economic conditions;

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Weather conditions;

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Political conditions in the Middle East and other oil producing regions;

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Domestic and foreign governmental regulations;

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The level of consumer product demand; and

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The price and availability of alternative fuels.

We cannot predict future natural gas or oil prices with any certainty. While rising demand for natural gas to fuel power generation and to meet increasingly stringent environmental requirements has led some observers to believe that long term demand for natural gas is increasing, there can be no assurance that this will be the case.

Our success depends on natural gas prices in the specific areas where we operate, and these prices may be lower than prices at major markets.

Even though overall natural gas prices at major markets, such as Henry Hub in Louisiana, may be high, regional natural gas prices may move somewhat independent of broad industry price trends. Because some of our operations are located outside major markets, we are directly impacted by regional natural gas prices regardless of Henry Hub or other major market pricing. For example, surplus natural gas supplies relative to available transportation in the Powder River Basin in 2002 caused local natural gas prices to be much less than national natural gas prices, and we, therefore, were unable to take advantage of those higher national natural gas prices. Low natural gas prices in any or all of the areas where we operate would negatively impact our business, financial condition and results of operations.

Index to Financial Statements

Natural gas and oil reserves are depleting assets and the failure to replace our reserves would adversely affect our production and cash flows.

Our future natural gas and oil production depends on our success in finding or acquiring new reserves. If we fail to replace reserves, our level of production and cash flows would be adversely impacted. Production from natural gas and oil properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. If we are not successful, our future production and revenues will be adversely affected.

Exploration is a high risk activity, and our participation in drilling activities may not be successful.

Our future success will largely depend on the success of our exploration drilling program. Participation in exploration drilling activities involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

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Unexpected drilling conditions;

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Blowouts, fires or explosions with resultant injury, death or environmental damage;

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Pressure or irregularities in formations;

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Equipment failures or accidents;

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Adverse weather conditions;

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Compliance with governmental requirements and laws, present and future; and

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Shortages or delays in the availability of drilling rigs and the delivery of equipment.

We use available seismic data to assist in the location of potential drilling sites. Even when properly used and interpreted, 2-D and 3-D seismic data and other visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. Poor results from our drilling activities would materially and adversely affect our future cash flows and results of operations. In addition, using seismic data and other advanced technologies involves substantial upfront costs and is more expensive than traditional drilling strategies, and we could incur losses as a result of these expenditures.

Our level of indebtedness reduces our financial and operational flexibility, and our level of indebtedness may increase.

As of June 30, 2005, the principal amount of our total indebtedness was $111.0 million. Our level of indebtedness affects our operations in several ways, including the following:

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A significant portion of our cash flow must be used to service our indebtedness;

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A high level of debt increases our vulnerability to general adverse economic and industry conditions;

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The covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow additional funds, dispose of assets, pay dividends, sell common shares below certain prices and make certain investments;

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Our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy or in our industry;

Index to Financial Statements

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A high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general corporate purposes; and

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A default under our senior loan covenants could result in required principal payments that we may not be able to meet, resulting in higher penalty interest rates and/or debt maturity acceleration.

We may incur additional debt, including significant additional secured indebtedness, in order to make future acquisitions or to develop our properties. A higher level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, natural gas and oil prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flow to pay the interest on our debt and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

If we are unable to raise substantial amounts of additional capital, we may not be able to maximize our business plan.

In order to maximize our business plan, we will need to raise substantial amounts of new capital. If we experience difficulties in raising equity or debt capital, we may be required to scale back our business plan by limiting acquisitions and our drilling and development program. Restrictions imposed under our senior secured notes may limit our ability to borrow additional funds.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present values of our reserves.

The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves.

There are many uncertainties inherent in estimating natural gas and oil reserves and their values, many of which are beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas or oil that cannot be measured in an exact manner. Estimates of economically recoverable natural gas or oil reserves and of future net cash flows necessarily depend on many variables and assumptions, such as:

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Historical natural gas or oil production from that area, compared with production from other producing areas;

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The assumed effects of regulations by governmental agencies;

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Assumptions concerning future prices;

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Assumptions concerning future operating costs;

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Assumptions concerning severance and excise taxes; and

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Assumptions concerning development costs and workover and remedial costs.

Any of these assumptions could vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of natural gas or oil attributable to any particular group of properties, classifications of those reserves based on risk recovery and estimates of the future net cash flows expected from them prepared by different engineers, or by the same engineer at different times, may vary substantially. Because of this, our reserve estimates may materially change at any time.

Index to Financial Statements

You should not consider the present values of estimated future net cash flows referred to in this prospectus to be the current market value of the estimated reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are generally based on prices and costs in effect when the estimate is made. However, actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:

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The amount and timing of actual production, supply and demand for natural gas or oil;

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Curtailments or increases in consumption by natural gas or oil purchasers;

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Changes in governmental regulations or taxation; and

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The timing of both production and expenses in connection with the development and production of natural gas or oil properties.

In this prospectus, the net present value of future net revenues is calculated using a 10% discount rate. This rate is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the natural gas and oil industry in general.

We rely on the accuracy of the estimates in the reservoir engineering reports provided to us by our outside engineers, and if they prove to be inaccurate, our future financial performance and results of operations may be adversely affected.

We have no in house reservoir engineering capability, and therefore rely on the accuracy of the periodic reservoir reports provided to use by our outside reservoir engineers. If those reports prove to be inaccurate, a revision of reserves may result in further write downs in the carrying value of our natural gas and oil properties. Inaccurate estimates may also significantly impact our operational planning. Further, we use the reports of our independent reservoir engineers in our financial planning. If the reports of the outside reservoir engineers prove to be inaccurate, we may make misjudgments in our financial planning.

The imprecise nature of estimating proved natural gas and oil reserves, future downward revisions of proved reserves and increased drilling expenditures without current additions to proved reserves may lead to write downs in the carrying value of our natural gas and oil properties.

Due to the imprecise nature of estimating natural gas and oil reserves as well as the potential volatility in natural gas and oil prices and their effect on the carrying value of our natural gas and oil properties, there can be no assurance that write downs in the future will not be required as a result of factors that may negatively affect the present value of proved natural gas and oil reserves. These factors can include volatile natural gas and oil prices, downward revisions in estimated proved natural gas and oil reserve quantities, limited classification of proved reserves associated with successful wells and unsuccessful drilling activities.

Deficiencies of title to our leased interests could result in significant losses.

Our practice in acquiring exploration leases or undivided interests in natural gas and oil leases is not to incur the expense of retaining lawyers to examine the title to the mineral interest prior to executing the lease. Instead, we rely upon the judgment of lease brokers and others to perform the field work in examining records in the appropriate governmental or county clerk’s office before leasing a specific mineral interest. This practice is widely followed in the industry. Prior to the drilling of an exploration well the operator of the well will typically obtain a preliminary title review of the drillsite lease and/or spacing unit within which the proposed well is to be drilled to identify any obvious deficiencies in title to the well and, if there are deficiencies, to identify measures necessary to cure those defects to the extent reasonably possible. We have no assurance, however, that any such deficiencies have been cured by the operator of any such wells. It does happen, from time to time, that the examination made by the title lawyers reveals that the lease or leases are invalid, having been purchased in error from a person who is not the rightful owner of the mineral interest desired. In these circumstances, we may not be able to proceed with our exploration and development of the lease site or may incur costs to remedy a defect.

Index to Financial Statements

We may experience shortages of equipment and personnel, which could significantly disrupt or delay our operations.

From time to time, there has been a general shortage of drilling rigs, equipment, supplies and oilfield services in North America and Australia, which we believe may intensify because of current increased industry activity. In addition, the costs and delivery times of rigs, equipment and supplies have risen. Shortages of drilling rigs, equipment, supplies or trained personnel could delay and adversely affect our operations and drilling plans, which could have an adverse effect on our business. While we intend to enter into contracts for the services of drilling rigs in North America and Australia, we may not be successful in doing so.

The demand for, and wage rates of, qualified rig crews have begun to rise in the drilling industry due to the increasing number of active rigs in service. Personnel shortages have occurred in the past during times of increasing demand for drilling services. If the number of active drilling rigs increases, we may experience shortages of qualified personnel to operate our drilling rigs, which could delay our drilling operations and adversely affect our business.

We are subject to complex laws and regulations, including environmental laws and regulations that can adversely affect the cost, manner or feasibility of conducting our business.

Our exploration and production interests and operations are subject to stringent and complex federal, state and local laws and regulations governing the operation and maintenance of our facilities and the handling and discharge of substances into the environment. These existing laws and regulations impose numerous obligations that are applicable to our interests and operations including:

•

Air and water discharge permits for drilling and production operations;

•

Drilling and abandonment bonds or other financial responsibility assurances;

•

Reports concerning operations;

•

Spacing of wells;

•

Access to properties, particularly in the Powder River Basin;

•

Taxation; and

•

Other regulatory controls on operating activities.

In addition, regulatory agencies have from time to time imposed price controls and limitations on production by restricting the flow rate of wells below actual production capacity in order to conserve supplies of natural gas and oil.

Failure to comply with environmental and other laws and regulations applicable to our interests and operations could result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining or limiting future operations; any of which could have a material adverse affect on us. Legal requirements are sometimes unclear and are frequently changed in response to economic or political conditions. As a result, it is hard to predict the ultimate cost of compliance with these requirements or their affect on our interests and operations. In addition, there can be no assurance that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not have a material adverse affect on our business.

The production, handling, storage, transportation and disposal of natural gas and oil, by-products of natural gas and oil and other substances produced or used in connection with natural gas and oil production operations are regulated by laws and regulations focused on the protection of human health and the environment. Consequently, the discharge or release of natural gas, oil or other substances into the air, soil or water could subject us to liabilities arising from environmental cleanup and restoration costs, claims made by neighboring

Index to Financial Statements

landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover some or any of these costs from insurance.

Our Australian operations are subject to unique risks relating to Aboriginal land claims and government licenses.

Our Australian operations could be affected by native title claims by Aboriginal groups. Australian law recognizes that in some instances native title, that is the laws and customs of the Aboriginal inhabitants, has survived European settlement. Native title will only survive if it has not been extinguished. Native title may be extinguished by an Act of Government, such as the creation of a title that is inconsistent with native title. This may include a grant of the right to exclusive possession through freehold title or lease. Native title may also be extinguished if the connection between the land and the group of Aboriginal people claiming native title has been lost. Each authority to prospect, and license in areas in which we desire to engage in exploration or production activities must be examined individually in order to determine the validity of any native title claim. We may be required to negotiate with any Aborigines who can make a valid claim to having ancestral ties to the areas in which we desire to engage in exploration or production activities. These negotiations could both delay the timing of our exploration or production activities, as well as add an additional layer of cost or a requirement to share revenues if any Aboriginal claimants are proved to have native title rights in the exploration areas.

The process of drilling for and producing natural gas and oil involves many operating risks that can cause substantial losses, and we may not have enough insurance to cover these risks adequately.

The natural gas and oil business involves many operating hazards, such as:

•

Well blowouts, fires and explosions;

•

Surface craterings and casing collapses;

•

Uncontrollable flows of natural gas, oil or well fluids;

•

Pipe and cement failures;

•

Formations with abnormal pressures;

•

Stuck drilling and service tools;

•

Pipeline ruptures or spills;

•

Natural disasters; and

•

Releases of toxic natural gas.

Any of these events could cause substantial losses to us as a result of:

•

Injury or death;

•

Damage to and destruction of property, natural resources and equipment;

•

Pollution and other environmental damage;

•

Regulatory investigations and penalties;

•

Suspension of operations; and

•

Repair and remediation costs.

We could also be responsible for environmental damage caused by previous owners of property that we purchase or lease. As a result, we may incur substantial liabilities to third parties or governmental entities. See

Index to Financial Statements

“Business—Governmental Regulation” and “Business—Environmental Regulation”. Although we maintain what we believe is appropriate and customary insurance for these risks, the insurance may not be available or sufficient to cover all of these liabilities. If these liabilities are not covered by our insurance, paying them could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties.

Our ability to market our natural gas and oil may be impaired by capacity constraints on the gathering systems and pipelines that transport our natural gas and oil.

The availability of a ready market for our natural gas production depends on the proximity of our reserves to and the capacity of natural gas gathering systems, pipelines and trucking or terminal facilities. We enter into agreements with companies that own pipelines used to transport natural gas from the wellhead to contract destination. Those pipelines are limited in size and volume of natural gas flow. Should production begin, other outstanding contracts with other producers and developers could interfere with our access to a natural gas line to deliver natural gas to the market. We do not own or operate any natural gas lines or distribution facilities. Further, interstate transportation and distribution of natural gas is regulated by the federal government through the Federal Energy Regulatory Commission, or FERC. FERC sets rules and carries out administratively the oversight of interstate markets for natural gas and other energy policy. Among FERC’s powers is the ability to dictate sale and delivery of natural gas to any markets it oversees.

Additionally, state regulators have vast powers over sale, supply and delivery of natural gas and oil within their state borders. While we do employ certain companies to represent our interests before state regulatory agencies, there can be no assurance that our interests will receive favorable rulings from any state agency, or that some future occurrence will not drastically alter our ability to enter into contracts or deliver natural gas to the market.

Competition in the natural gas and oil industry is intense, and we are smaller and have a more limited operating history than most of our competitors.

We operate in a highly competitive environment. We compete with other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Our competitors include major integrated natural gas and oil companies, numerous independent natural gas and oil companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies that have substantially larger operating staffs and greater capital resources than we do and that, in many instances, have been engaged in the natural gas and oil business for a much longer time than we have. These companies may be able to pay more for exploratory prospects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase more properties and prospects than our financial and human resources permit. In addition, these companies may be able to spend more on the existing and changing technologies that we believe are and will be increasingly important to the current and future success of natural gas and oil companies. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

Acquisition prospects are difficult to assess and may pose additional risks to our operations.

Where appropriate, we may evaluate and pursue acquisition opportunities on terms our management considers favorable. In particular, we expect to pursue acquisitions that have the potential to economically increase our natural gas and oil reserves. The successful acquisition of natural gas and oil properties requires an assessment of:

•

Recoverable reserves;

•

Exploration potential;

Index to Financial Statements

•

Future natural gas and oil prices;

•

Operating costs;

•

Potential environmental and other liabilities; and

•

Permitting and other environmental authorizations required for our operations.

In connection with such an assessment, we would expect to perform a review of the subject properties that we believe to be generally consistent with industry practices. Nonetheless, the resulting conclusions are inexact and their accuracy inherently uncertain, and such an assessment may not reveal all existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every platform or well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken.

Future acquisitions could pose additional risks to our operations and financial results, including:

•

Problems integrating the purchased operations, personnel or technologies;

•

Unanticipated costs;

•

Diversion of resources and management attention from our exploration business;

•

Entry into regions or markets in which we have limited or no prior experience; and

•

Potential loss of key employees, particularly those of the acquired organization.

We cannot control the activities on properties we do not operate, which may affect the timing and success of our future operations.

Other companies operate some of the properties in which we have an interest. As a result, we have a limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors that are outside of our control, including:

•

Timing and amount of capital expenditures;

•

The operator’s expertise and financial resources;

•

Approval of other participants in drilling wells; and

•

Selection of technology.

Technological changes could affect our operations.

The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement such new technologies at substantial costs. In addition, other natural gas and oil companies have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may be unable to respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost. One or more of the technologies that we currently use or may implement in the future may become obsolete.

Rapid growth could result in a strain on our resources.

Because of our size, our growth, if achieved, will likely place a significant strain on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative,

Index to Financial Statements

operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of experienced managers, geoscientists and engineers, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

Our ability to successfully execute our business plan is dependent on our ability to obtain adequate financing.

Our business plan, which includes participation in 3-D seismic shoots, the drilling of exploration prospects and development projects and producing property acquisitions, has required and will continue to require substantial capital expenditures. We may require additional financing to fund our planned growth. Our ability to raise additional capital will depend on the results of our operations and the status of various capital and industry markets at the time we seek such capital. Accordingly, we cannot be certain that additional financing will be available to us on acceptable terms, if at all. In particular, the terms of our senior secured notes limit our ability to incur additional indebtedness. In the event additional capital resources are unavailable, we may be required to curtail our exploration and development activities or be forced to sell some of our assets in an untimely fashion or on less than favorable terms.

Not hedging our production may result in losses.

We currently do not hedge our natural gas and oil production. By not hedging our production, we may be more adversely affected by declines in natural gas and oil prices than our competitors who engage in hedging arrangements. Further, should we elect to hedge in the future, such hedges may result in us receiving lower than current prevailing market prices and place additional financial strains on us due to having to post margin calls on our hedges.

Exchange rate fluctuations subject us to unique risks.

As our Australian activities increase, we will be increasingly exposed to the impact of fluctuations in the exchange rate between the Australian dollar and the U.S. dollar. We have only minimal exposure to Canadian currency fluctuations, as almost all of our current revenues and expenses are in U.S. dollars.

We depend on our key personnel, the loss of which could adversely affect our operations and financial performance.

We depend to a large extent on the services of a limited number of senior management personnel and directors. The loss of the services of these individuals could negatively impact our future operation. We have employment contracts with certain members of our senior management team; although, we do not maintain key-man life insurance on any of our senior management. We believe that our success is also dependent on our ability to continue to retain the services of skilled technical personnel. Our inability to retain skilled technical personnel could have a material adverse effect on our business.

Geostar Corporation is a major shareholder and is in a position to significantly influence the activities and operations of certain jointly owned properties, which also could result in conflicts of interest.

As of August 1, 2005, Geostar owned approximately 9.8% of our outstanding common shares. As a result, Geostar is in a position to heavily influence the outcome of matters requiring a shareholder vote, including the election of directors, the adoption or amendment of provisions in our Articles of Incorporation and Bylaws and the approval of mergers and other significant corporate transactions. Geostar’s high level of ownership may also delay, defer or prevent a change in control of us and may adversely affect the voting and other rights of other shareholders.

The chairman of our board of directors is also a director and chief executive officer of Geostar. In accordance with the laws of Alberta, our directors are required to act honestly and in good faith with a view to

Index to Financial Statements

our best interests. The Geostar director on our board of directors also has fiduciary duties to manage Geostar, including its investments in companies such as us, in a manner beneficial to Geostar and its shareholders. In some circumstances, these duties may conflict with his duties as a director of Gastar. Addressing matters, such as board of director conflicts, are subject to the procedures and remedies as provided under the Business Corporations Act (Alberta). See “Description of Capital Stock—Board of Directors; Election and Removal of Directors”.

Geostar and its other subsidiaries are also engaged in the natural gas and oil business. Although we have entered into the Participating and Operating Agreement, or POA, with Geostar dated 2001, it is possible that we may in some circumstances be in direct or indirect competition with Geostar, including competition with respect to certain business strategies and transactions that we may propose to undertake. There can be no assurance that these conflicts of interest will not materially adversely affect us.

Some of our directors may not be subject to suit in the United States.

Three of our directors reside in Canada. As a result, it may be difficult or impossible to effect service of process within the United States upon those directors, to bring suit against them in the United States or to enforce in the United States courts any judgment obtained there against them predicated upon any civil liability provisions of the United States federal securities laws.

Risks Related to this Offering

There is a limited public market for our common shares.

Although our common shares have been listed on The Toronto Stock Exchange since January 2002, they are thinly traded. As a result, a trade involving a large number of common shares could have an exaggerated effect on the reported market price of our common shares. A holder of our common shares may not be able to liquidate his or her investment in a short time period or at the market prices that currently exist at the time the holder decides to sell. The purchase and sale of relatively small common share positions may result in disproportionately large increases or decreases in the price of our common shares.

Our common share price has been and is likely to continue to be highly volatile.

The trading price of our common shares are subject to wide fluctuations in response to a variety of factors, including quarterly variations in operating results, announcements of drilling and rig activity, economic conditions in the natural gas and oil industry, general economic conditions or other events or factors that our beyond our control. See “Price Range of Common Shares”.

In addition, the stock market in general and the market for natural gas and oil exploration companies in particular have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating results or asset values of those companies. These broad market and industry factors may seriously impact the market price and trading volume of our common shares regardless of our actual operating performance. In the past, following periods of volatility in the overall market and in the market price of a company’s securities, securities class action litigation has been instituted against these companies. If this type of litigation were instituted against us following a period of volatility in our common shares trading price, it could result in substantial costs and a diversion of our management’s attention and resources, which could have a materially adverse impact on our operations.

Future issuances of our common shares may adversely affect the price of our common shares.

The future issuance of a substantial number of common shares into the public market, or the perception that such issuance could occur, could adversely affect the prevailing market price of our common shares. A decline in the price of our common shares could make it more difficult to raise funds through future offerings of our

Index to Financial Statements

common shares or securities convertible into common shares. Following the effectiveness of the registration statement to which this prospectus is a part, we believe that substantially all of our outstanding common shares, our common shares that are issued in the future upon the exercise of outstanding options and the common shares issued upon conversion and exercise of the convertible debentures and warrants or additional common shares required to be issued under subscription receipts will be tradable under the U.S. federal securities laws.

Issuance of the common shares upon exercise of warrants and conversion of convertible debentures, together with additional issuances of common shares to purchasers of our senior secured notes for no additional consideration, will dilute the ownership interest of existing shareholders and could adversely affect the market price of our common shares.

We are obligated to issue a substantial number of common shares upon exercise of outstanding common share purchase warrants and upon conversion of our convertible debentures. We are also committed to issue on each of three dates during the next eighteen months additional common shares equal in value to CDN$4.5 million, based upon then current market prices. These issuances will dilute the ownership interest of existing shareholders. Any sales in the public market of the common shares issuable upon such exercise of warrants, conversion, or issuance of additional common shares could adversely affect prevailing market prices of our common shares. In addition, the existence of these warrants and convertible debentures may encourage short selling by market participants.

If we are unable to meet the Securities and Exchange Commission’s requirements related to the assessment, attestation and effectiveness of our internal controls, we may suffer a loss of investor confidence and the price of our common shares may be adversely affected.

Under the Exchange Act, we will be required to include in our annual report a report on internal controls. This report must state management’s responsibility for establishing and maintaining an adequate internal control structure and procedures for financial reporting. The report must also contain an assessment as of the end of the year of the effectiveness of those internal controls. The Exchange Act also requires our registered public accounting firm to test and report on the assessment made by management. Assuming effectiveness of this prospectus during the year 2005, these new rules are effective for us for the year ending December 31, 2006. In order to meet these requirements, we must document and test the effectiveness of our internal controls and then allow time for our registered public accounting firm to audit our internal control structure. The amount of work required by us to prepare, maintain and test our internal control structure could be extensive. In the event that management is unable to complete its assessment of the effectiveness of our internal controls over financial reporting or our auditors are unable to attest to management’s assessment or do their own assessment, or if these internal controls are not effective, we might experience an adverse reaction in the financial marketplace due to a loss of investor confidence in the reliability of our financial statements, which could negatively impact the market price of our common shares.

Index to Financial Statements

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

Some of the information included in this prospectus contains “forward-looking statements”. These statements can be identified by the use of forward-looking words, including “may”, “expect”, “anticipate”, “plan”, “project”, “believe”, “estimate”, “intend”, “will”, “should” or other similar words. Forward-looking statements may include statements that relate to, among other things:

•

Our financial position;

•

Business strategy and budgets;

•

Anticipated capital expenditures;

•

Drilling of wells;

•

Natural gas and oil reserves;

•

Timing and amount of future production of natural gas and oil;

•

Operating costs and other expenses;

•

Cash flow and anticipated liquidity;

•

Prospect development; and

•

Property acquisitions and sales.

Although we believe the expectations reflected in such forward-looking statements are reasonable, we cannot assure you that such expectations will occur. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from actual future results expressed or implied by the forward-looking statements. These factors include among others:

•

Low and/or declining prices for natural gas and oil;

•

Natural gas and oil price volatility;

•

The risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry holes;

•

Ability to raise capital to fund capital expenditures;

•

The ability to find, acquire, market, develop and produce new natural gas and oil properties;

•

Uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures;

•

Operating hazards attendant to the natural gas and oil business;

•

Downhole drilling and completion risks that are generally not recoverable from third parties or insurance;

•

Potential mechanical failure or under-performance of significant wells or pipeline mishaps;

•

Weather conditions;

•

Availability and cost of material and equipment;

•

Delays in anticipated start-up dates;

•

Actions or inactions of third-party operators of our properties;

•

Ability to find and retain skilled personnel;

Index to Financial Statements

•

Strength and financial resources of competitors;

•

Federal and state regulatory developments and approvals;

•

Environmental risks;

•

Worldwide economic conditions; and

•

Operational and financial risks associated with foreign exploration and production.

You should not unduly rely on these forward-looking statements in this prospectus, as they speak only as of the date of this prospectus. Except as required by law, we undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this prospectus or to reflect the occurrence of unanticipated events. See the information under the heading “Risk Factors” in this prospectus for some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in forward-looking statements.

USE OF PROCEEDS

We will not receive any of the proceeds from the sale of the common shares by the selling shareholders under this prospectus. All proceeds from the sale of those shares will be for the respective accounts of the selling shareholders.

PRICE RANGE OF COMMON SHARES

Our common shares are listed on The Toronto Stock Exchange under the symbol “YGA” and may be traded on the OTC Bulletin Board under the symbol “GSREF.PK”. Our common shares are not listed on any U.S. or other stock exchange or quoted in any U.S. or other quotation system. The following table sets forth the high and low sale prices of our common shares as reported on The Toronto Stock Exchange (CDN$) and as quoted in the United States in the “pink sheets” over-the-counter market for the periods presented. The prices in the table below have been adjusted for stock splits.


	Toronto Stock Exchange				OTC Bulletin Board
	High		Low		High		Low
2005
Third Quarter (through August 1, 2005)	CDN$	3.72	CDN$	2.88	$	3.15	$	2.40
Second Quarter	CDN$	4.48	CDN$	3.38	$	3.85	$	2.74
First Quarter	CDN$	4.95	CDN$	3.64	$	3.92	$	3.02

2004
Fourth Quarter	CDN$	5.50	CDN$	3.65	$	4.24	$	3.00
Third Quarter	CDN$	4.50	CDN$	3.28	$	3.52	$	2.11
Second Quarter	CDN$	4.35	CDN$	3.40	$	3.17	$	2.61
First Quarter	CDN$	4.50	CDN$	2.40	$	3.19	$	1.87

2003
Fourth Quarter	CDN$	2.65	CDN$	2.30	$	1.98	$	1.70
Third Quarter	CDN$	2.53	CDN$	2.00	$	1.87	$	1.41
Second Quarter	CDN$	2.24	CDN$	1.98	$	1.58	$	1.39
First Quarter	CDN$	2.32	CDN$	1.95	$	1.55	$	1.36

As of August 1, 2005, there were 445 holders of record of our common shares. The last reported sale prices of our common shares on The Toronto Stock Exchange and as quoted in the United States in the “pink sheets” over-the-counter market on August 1, 2005 were CDN$3.30 and $2.68, respectively.

Index to Financial Statements

As of August 1, 2005, 17,329,600 common shares were subject to outstanding stock options granted under our 2002 Stock Option Plan, 11,705,850 shares of which are vested but have not been exercised, and 4,997,288 common shares were subject to outstanding warrants, all of which shares were exercisable as of such date. As of August 1, 2005, we had outstanding $30.0 million in principal amount of convertible debentures. The convertible debentures are convertible at the option of the holders into an aggregate of 6,849,315 common shares.

As of August 1, 2005, 1,650,133 common shares were eligible for resale pursuant to Rule 144 under the Securities Act, excluding the shares covered by this prospectus. Pursuant to the indenture governing the convertible debentures and the terms of the certain warrants, we have agreed to register for resale the 6,849,315 common shares issuable upon the conversion of our convertible debentures and the 2,759,740 common shares issuable upon exercise of the placement agent warrants, all of which shares are covered by this prospectus. Pursuant to the terms of our senior secured notes, we have agreed to register for resale the 1,217,269 common shares issued or issuable in connection with the sale of our senior secured notes, all of which are covered by this prospectus, plus up to an estimated 4,340,836 additional common shares to be issued pursuant to subscription rights at various dates pursuant to the terms of the original sale of the registrant’s senior secured notes.

DIVIDEND HISTORY

We have never declared or paid any cash dividends on our common shares. We anticipate that we will retain any future earnings, if any, to satisfy our operational and other cash needs and do not anticipate paying any cash dividends on our common shares in the foreseeable future. In addition, our current senior secured notes prohibit us from paying cash dividends as long as such debt remains outstanding.

Pursuant to the provisions of the Business Corporations Act (Alberta), we are prohibited from declaring or paying a dividend if there are reasonable grounds for believing that (1) we are, or would after the payment be, unable to pay our liabilities as they become due or (2) the realizable value of our assets would thereby be less than the aggregate of our liabilities and stated capital of all classes.

For a discussion of Canadian laws, decrees and regulations that restrict the import or export of capital, affect the remittance of dividends or other payments to non-resident holders of our common shares, or relate to taxes, including withholding provisions, to which U.S. holders of our common shares are subject, as well as pertinent provisions of the tax treaty between Canada and the United States, please see “Material Income Tax Consequences”.

Index to Financial Statements

SELECTED HISTORICAL FINANCIAL AND OPERATIONAL INFORMATION

The following table presents selected historical financial and operational information as of and for the periods indicated. The selected consolidated financial data as of and for the years ended December 31, 2004, 2003, 2002, 2001 and 2000 are derived from our audited consolidated financial statements. The selected consolidated financial data as of March 31, 2005 and for the three months ended March 31, 2005 and 2004 are derived from our unaudited consolidated financial statements. On May 16, 2000, we changed our name to Gastar Exploration Ltd. and began our natural gas and oil operations. Prior to May 16, 2000, we engaged in limited minerals exploration activities under the name CopperQuest Inc.

You should read the following selected consolidated financial and operational information in conjunction with our audited and unaudited consolidated financial statements and the accompanying notes included elsewhere in this prospectus and the section of this prospectus entitled, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.


	As of and for the Three Months Ended March 31,						As of and for the Years Ended December 31,
	2005			2004			2004			2003			2002			2001			2000
	(Unaudited)
	(in thousands, except per share amounts)
Consolidated Statement of Loss Data:
Revenues	$	4,731		$	356		$	6,059		$	1,461		$	783		$	228		$	—
Depletion, depreciation and amortization	$	2,690		$	176		$	3,233		$	572		$	360		$	67		$	—
Impairment of natural gas and oil properties	$	4,410		$	—		$	6,306		$	552		$	377		$	3,960		$	127
Lease operating, transportation and selling	$	1,315		$	211		$	2,000		$	712		$	769		$	138		$	—
General and administrative expense	$	1,765		$	167		$	4,023		$	1,909		$	1,933		$	1,008		$	198
Operating loss before interest expense	$	(5,497	)	$	(242	)	$	(9,587	)	$	(2,368	)	$	(2,657	)	$	(4,960	)	$	(382	)
Net loss	$	(7,636	)	$	(670	)	$	(12,776	)	$	(4,947	)	$	(4,599	)	$	(4,793	)	$	(382	)
Basic and diluted loss per share	$	(0.07	)	$	(0.01	)	$	(0.12	)	$	(0.05	)	$	(0.05	)	$	(0.05	)	$	(0.0	)
Shares used in the calculation of basic and diluted loss per share		113,788			107,265			111,374			104,958			98,618			94,648			80,435

Consolidated Balance Sheet Data:
Net natural gas and oil properties	$	63,363					$	56,556		$	35,791		$	34,457		$	23,069		$	8,411
Long term liabilities	$	60,096					$	60,668		$	3,992		$	12,291		$	1,877		$	—
Total shareholders’ equity	$	15,157					$	21,976		$	23,669		$	22,430		$	17,656		$	18,180

Production Data (1):
Production:
Natural gas (MMcf)		849.0			83.3			1,108.0			385.0			393.2			81.7			—
Oil (MBbl)		0.7			0.0			1.8			1.0			3.1			2.8			—
Oil Natural gas equivalents (Mmcfe)		853.2			83.4			1,118.8			391.0			411.6			98.5			—

Natural gas (MMcfd)		9.4			0.9			3.0			1.1			1.1			0.2			—
Oil (MBod)		0.0			0.0			0.0			0.0			0.0			0.0			—
Oil Natural gas equivalents (Mmcfed)		9.5			0.9			3.1			1.1			1.1			0.3			—

Average Sales Prices:
Natural gas (per Mcf)	$	5.53		$	3.47		$	5.40		$	3.72		$	1.33		$	1.83		$	—
Oil (per Bbl)	$	48.80		$	31.13		$	40.08		$	27.89		$	20.15		$	20.55		$	—

(1)	There was no reportable production of natural gas and oil prior to 2001.

Index to Financial Statements

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with accompanying financial statements and related notes included elsewhere in this prospectus. It contains forward looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and oil, economic and competitive conditions, regulatory changes, estimates of proved reserves, potential failure to achieve production from development projects, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Notes Regarding Forward Looking Statements”, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward looking events discussed may not occur.

Gastar Exploration Ltd.

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. Our principal business activities include the identification, acquisition, and subsequent exploration and development of natural gas and oil properties. Our emphasis is on prospective deep structures identified through seismic and other analytical techniques as well as unconventional natural gas reserves, such as coal bed methane. We currently are pursuing conventional natural gas exploration in the Deep Bossier play in the Hilltop area in East Texas and the Appalachian Basin in West Virginia. In our coal bed methane, or CBM, projects, we use advanced technologies to assist us in developing commercial natural gas production from known coal beds. Our primary CBM properties are in the United States in the Powder River Basin and in the Gunnedah and Gippsland Basins of Australia.

Recent Operational Events. Management believes that the following recent operational events are important to the success of our business plan:

•

The Fridkin-Kaufman #1, or F-K #1, well is a Deep Bossier sand well located in the Hilltop area of East Texas, commenced production in late September 2004, with initial production rates of approximately 15.0 MMcfd (8.5 MMcfd). As a result of the Geostar acquisition, our working interest increased from 75% to 98%. Current daily production is approximately 6.4 MMcfd (4.8 MMcfd net). A 20.0 MMcfd natural gas processing plant has been built at the F-K #1 well site.

•

The Cheney #1 well completed drilling in the Hilltop area to test the Deep Bossier sand encountered in the F-K #1 well. This well is approximately one mile north of the F-K #1 well. The Cheney #1 well encountered approximately 400 net feet of potential pay zones based on natural gas shows while drilling and on logs. The well commenced production in mid-February 2005 at an initial rate of approximately 7.0 MMcfd (4.0 MMcfd). As a result of the Geostar acquisition, our working interest increased from 75% to 98%. Current daily production is approximately 1.0 MMcfd (0.8 MMcfd net). We believe that our initial fracture stimulation of the primary pay zone in the Cheney #1 well was not effective, and we are planning to re-stimulate this well in August 2005. A 20.0 MMcfd natural gas processing plant has been constructed on the Cheney #1 well site.

•

We completed drilling the Lone Oak Ranch #1 well in the Hilltop area and began production operations in early May 2005 at an initial rate of approximately 7.0 MMcfd (3.8 MMcfd net). As a result of the Geostar acquisition, our working interest increased from 73% to 98%. Current daily production is approximately 5.7 MMcfd (4.2 MMcfd net).

Index to Financial Statements

•

We began drilling the Greer #1 well, our fourth Bossier sand well in the Hilltop area in January 2005. The Greer #1 well is located approximately one mile from the F-K #1well. We drilled the Greer #1 well to a total depth of 17,800 feet. Based on natural gas shows during drilling and electric logs, the well encountered approximately 57 net feet of apparent pay with high indicative porosity similar to the producing zones in our previous wells. As a result of the Geostar acquisition, our working interest increased from 73% to 98%. The well commenced production in July 2005 at an initial rate of approximately 5.0 MMcfd (3.9 MMcfd net).

•

Drilling commenced in February 2005 on the Fridkin-Kaufman #2, or F-K #2, well to a total depth of 18,700 feet. Based on electric logs, the well encountered approximately 74 net feet of apparent pay in the Bossier lower “K” sand below 18,000 feet. The well also encountered over 120 feet of indicated pay in the shallower Travis Peak formation. The well is located approximately 2,200 feet from the F-K #1 well. Planned completion activities are expected to take approximately 60 days and, if successful, initial production is expected by mid-September 2005. As a result of the Geostar acquisition, our working interest increased from 78% to 100%.

•

Drilling commenced in May 2005 on the Donelson #1 well with a projected depth of between 17,500 and 19,000 feet. The well is currently drilling at a depth in excess of 13,000 feet. As a result of the Geostar acquisition our working interest increased from 78% to 100%.

•

Our CBM joint venture partners drilled and completed three vertical CBM wells and one horizontal CBM well during the third and fourth quarters of 2004 on our 2.0 million gross acre PEL 238 project in New South Wales, Australia. The vertical wells were fracture stimulated with large volumes of sand proppant. These wells commenced dewatering operations in the fourth quarter of 2004. The wells have demonstrated high water rates indicative of high permeability within the coal formation and have begun producing gas after 60 to 90 days of de-watering with several of the wells producing natural gas from first production. We believe that the performance of these wells to date is confirmation of the presence of a significant CBM deposit that can be developed on a commercial basis. Further evaluation activities are anticipated for the third and fourth quarters of 2005 and in the first quarter of 2006. During the first and second quarters of 2005, we drilled the first two dedicated CBM test wells on our EL 4416 license in the Gippsland Basin, located in Victoria, Australia. We hold a 75% working interest in the CBM and Mineral Sands rights on the 1.4 million gross acre concession with the balance owned and operated by a subsidiary of Geostar. The wells are anticipated to be completed during the third quarter utilizing open-hole completion techniques commonly used in the Powder River Basin area.

Results of Operations

The following is a comparative discussion of the results of operations for the three months ended March 31, 2005 and 2004 and for the years ended December 31, 2004, 2003 and 2002. It should be read in conjunction with the financial statements and the related notes and other information included elsewhere in this prospectus.

Three Months Ended March 31, 2005 compared to Three Months Ended March 31, 2004

Revenues. Substantially all of our revenues are derived from the production of natural gas in the United States. We reported revenues of $4.7 million for the three months ended March 31, 2005, up from $356,000 for the comparable period in 2004. This increase was attributable to the commencement of production of natural gas from the F-K #1 well in East Texas in the third quarter of 2004, the commencement of production from the Cheney #1 well in East Texas in the first quarter of 2005, additional production from new CBM wells drilled in the Powder River Basin and higher prices for both natural gas and oil. Of the increase in revenues, 60% was attributed to higher production rates and 40% resulted from price increases.

Index to Financial Statements

Natural Gas and Oil Production and Average Sales Prices. Natural gas represents substantially all of our production. The table below sets forth production and sales information for the periods indicated:


	Three Months Ended March 31,
	2005		2004
Production:
Natural gas (MMcf)		849.0		83.3
Oil (MBbls)		0.7		0.0
Total (MMcfe)		853.2		83.4

Natural gas (MMcfd)		9.4		0.9
Oil (MBod)		0.0		0.0
Total (MMcfed)		9.5		0.9

Average sales prices:
Natural gas (per Mcf)	$	5.53	$	3.47
Oil (per Bbl)	$	48.80	$	31.13

Depletion, depreciation and amortization. We reported depletion, depreciation and amortization (“DD&A”) of $2.7 million for the three months ended March 31, 2005, up from $176,000 for the comparable period in 2004. DD&A increased primarily due to higher production rates attributable to the F-K #1 well in East Texas that commenced production in the third quarter of 2004 and the Cheney #1 well in East Texas that commenced production in the first quarter of 2005. Of the increase in DD&A expense, 64% was attributed to higher production rates and 36% was due to an increase in DD&A rate per unit. The DD&A rate for the period ended March 31, 2005 was $3.15 per Mcfe, as compared to prior comparable period of $2.10 per Mcf due to higher capital expenditures in Texas.

Impairment of natural gas and oil properties. The impairment of natural gas and oil properties for the three months ended March 31, 2005 of $4.4 million was primarily due to the result of high initial drilling and completion costs on our Deep Bossier wells in East Texas coupled with limited production history that limited the current recording of proven reserves. No impairment was recorded in the first quarter of 2004.

Interest and debt related items. We reported interest and debt related items of $2.2 million for the three months ended March 31, 2005, up from $419,000 for the comparable period in 2004. This increase was due to higher debt outstanding as a result of the issuance of $15.0 million and $10.0 million senior unsecured notes, $3.25 million of subordinated unsecured notes and $30.0 million of convertible debentures in 2004.

Lease operating, transportation and selling. We reported expenses for lease operating, transportation and selling of $1.3 million for the three months ended March 31, 2005, up from $211,000 for the comparable period in 2004. This increase was attributable to higher production volumes and an increase in the number of producing wells. Our lease operating expense per Mcfe decreased to $1.54 per Mcfe during the first three months of 2005 from $2.44 per Mcfe for the comparable period.

General and administrative. We reported expenses for general and administrative of $1.8 million for the three months ended March 31, 2005, up from $167,000 for the comparable period in 2004. The increase in general and administrative expenses was primarily due to higher contract staff and professional service charges and the continued recording of compensation expense due to the issuance of stock options.

Year Ended December 31, 2004 compared to Year Ended December 31, 2003.

Revenues. Substantially all of our revenues are derived from the production of natural gas in the United States. We reported revenues of $6.1 million for the year ended December 31, 2004, up from $1.5 million for the

Index to Financial Statements

year ended December 31, 2003. This increase was attributable to the commencement of production of natural gas from the F-K #1 well in East Texas in the third quarter of 2004, additional production from new CBM wells drilled in the Powder River Basin, and higher commodity prices for both natural gas and oil. Of the increase in revenues, 59% was attributed to higher production rates and 41% resulted from price increases.


	Years Ended December 31,
	2004		2003
Production:
Natural gas (MMcf)		1,108.0		385.0
Oil (MBbls)		1.8		1.0
Total (MMcfe)		1,118.8		391.0

Natural gas (MMcfd)		3.0		1.1
Oil (MBod)		0.0		0.0
Total (MMcfed)		3.1		1.1

Average sales prices:
Natural gas (per Mcf)	$	5.40	$	3.72
Oil (per Bbl)	$	40.08	$	27.89

Depletion, depreciation and amortization. We reported depletion, depreciation and amortization of $3.2 million for the year ended December 31, 2004, up from $572,000 for the year ended December 31, 2003. This increase was attributable to the commencement of production of natural gas from the F-K #1 well in East Texas in the third quarter of 2004 and additional production from new CBM wells drilled in the Powder River Basin. Of the increase in DD&A expense, 40% was attributed to higher production rates and 60% was due to an increase in DD&A rate per unit. The DD&A rate for the period ended December 31, 2004 was $2.89 per Mcfe, as compared to $1.46 for the comparable period in 2003.

Impairment of natural gas and oil properties. We recorded an impairment of natural gas and oil properties of $6.3 million for the year ended December 31, 2004, up from $552,000 for the comparable period in 2003. The 2004 impairment was primarily due to the result of high initial drilling and completion costs on our Deep Bossier wells in East Texas coupled with limited production history that limited the current recording of proven reserves.

Interest and debt related items. We reported interest and debt related items of $3.2 million for the year ended December 31, 2004, up from $2.6 million for the year ended December 31, 2003. This increase was due to higher debt outstanding as a result of the issuance of $15.0 million and $10.0 million senior unsecured notes, $3.25 million of subordinated unsecured notes and $30.0 million of convertible debentures in 2004.

Lease operating, transportation and selling. We reported lease operating, transportation and selling expenses of $2.0 million for the year ended December 31, 2004, up from $712,000 for the year ended December 31, 2003. This increase was due to higher production volumes and an increased number of producing wells. Our lease operating expense per Mcfe decreased to $1.78 during the year-ended December 31, 2004 from $1.82 for the comparable period in 2003.

General and administrative. We reported general and administrative expenses of $4.0 million for the year ended December 31, 2004, up from $1.9 million for the year ended December 31, 2003. This increase in general and administrative expenses was primarily due to higher contract staff and professional service charges and the recording of compensation expense due to the issuance of stock options in April and August 2004.

Index to Financial Statements

Year Ended December 31, 2003 compared to Year Ended December 31, 2002.

Revenues. Substantially all of our revenues are derived from the production of natural gas in the United States. We reported revenues of $1.5 million for the year ended December 31, 2003, up from $783,000 for the year ended December 31, 2002. This increase was attributable to additional production from new CBM wells drilled in the Powder River Basin and higher commodity prices for both natural gas and oil. The increase in revenues was almost entirely attributable to price increases during the comparable periods.


	Years Ended December 31,
	2003		2002
Production:
Natural gas (MMcf)		385.0		393.2
Oil (MBbls)		1.0		3.1
Total (MMcfe)		391.0		411.6

Natural gas (M Mcfd)		1.1		1.1
Oil (MBod)		0.0		0.0
Total (MMcfed)		1.1		1.1

Average sales prices:
Natural gas (per Mcf)	$	3.72	$	1.33
Oil (per Bbl)	$	27.89	$	20.15

Depletion, depreciation and amortization. We reported depletion, depreciation and amortization of $572,000 for the year ended December 31, 2003, up from $360,000 for the year ended December 31, 2002. This increase was attributable to additional production from new CBM wells drilled in the Powder River Basin. The increase in DD&A was almost entirely attributable to increases in the DD&A rate. The DD&A rate for the period ended December 31, 2003 was $1.46 per Mcfe, as compared to $0.87 for the comparable period in 2002.

Impairment of natural gas and oil properties. We recorded an impairment of natural gas and oil properties of $552,000 for the year ended December 31, 2003, up from $377,000 for the comparable period in 2002. Of the 2003 impairment, the majority was primarily due to the entering into of the Powder River Basin Earn-In Joint Venture, which reduced our working interest. The 2002 impairment was all related to our Australian operations.

Interest and debt related items. We reported interest and debt related items of $2.6 million for the year ended December 31, 2003, up from $2.0 million for the year ended December 31, 2002. This increase was attributable to the issuance of $6.7 million of convertible debentures that was completed in 2003.

Lease operating, transportation and selling. We reported lease operating, transportation and selling of $712,000 for the year ended December 31, 2003, down from $769,000 for the year ended December 31, 2002. This 7% decrease was primarily attributable to the sale of certain Powder River Basin assets in the second quarter of 2003. Our lease operating expense per Mcfe increased to $1.82 during the year ended December 31, 2003 from $1.75 for the comparable period in 2002.

General and administrative. We reported general and administrative of $1.9 million for each of the years ended December 31, 2003 and 2002.

Recent Developments

Index to Financial Statements

bear interest at three month LIBOR plus 6% and mature on June 18, 2010. We also committed to issue to the purchasers of the notes, for no additional consideration, common shares in CDN$4.5 million increments on each of the six, twelve and eighteen-month anniversaries of the original note closing date valued on a five day weighted average trading price immediately prior to the date of issuance.

We have the right, exercisable quarterly during the period from August 17, 2005 to June 16, 2007, to require the original purchaser of the senior secured note to purchase additional notes in an amount limited to an aggregate of $20.0 million in principal, provided that we comply with certain financial and other covenants. If additional notes are issued, the purchasers will also be entitled to receive, for no additional consideration, additional common shares on similar terms as those issued with the original notes in a pro rata amount based on the additional principal amount of the notes. To issue these additional notes, we must meet certain requirements, including a minimum ratio of our present value, discounted at 10%, based on prices specified in the senior secured notes of proved plus probable reserves to net senior secured debt.

Business Environment

The price we receive for our natural gas production is influenced by both national gas price trends and regional gas prices. On a national basis, natural gas prices increased in 2004 generally due to increases in crude oil prices, economic growth and general concerns about future natural gas supplies. Since most of our production for the first three quarters of 2004 was located in the Powder River Basin of Wyoming, which sold at a significant discount to a major market such as Henry Hub. Colorado Interstate Gas Pipeline’s system is the major pricing location for our Powder River natural gas production.

With the beginning of our Texas production operations in the third quarter of 2004, the majority of our near term production is from Texas. For the first quarter 2005, natural gas production from our East Texas properties

Index to Financial Statements

accounted for approximately 80% of our total natural gas production. Natural gas prices for our Hilltop area production will generally be priced based on prices at the Katy, Texas regional hub. Although monthly variances occur in the price differentials between Katy Hub prices and Henry Hub prices, Katy Hub prices generally trade at a small discount to Henry Hub prices. Our Deep Bossier production generally is priced based on Katy Hub prices less gathering, processing and transportation fees.

Crude oil prices increased in 2004 due to perceived tight crude supplies, the continued conflict in Iraq, and increasing global demand lead by increased Asian demand for commodities, in particular energy-related commodities. Average crude oil prices in 2004 were significantly higher than the average 2003 prices. While substantially all of our production is natural gas, high crude prices help keep natural gas prices high by keeping alternative fuels, such as heating oil and residual fuel, expensive.

During early 2005, crude oil prices continued to firm, reaching prices not seen in many years. Continuing tightness of supply, stronger than expected economic growth and less sensitivity to higher energy prices in major global economies (United States, Europe and Asia) were credited with being the prime factors in higher sustained crude oil prices. The higher crude oil prices continued to support higher natural gas prices even though natural gas continued to trade at less than parity on an energy equivalent basis to crude oil.

We do not currently have any financial derivative or “hedge” positions on any of our future natural gas and oil sales. All natural gas and oil sales are either sold directly in spot markets or sold through marketing or sales contracts priced at daily or monthly spot prices.

Liquidity and Capital Resources

During the six months ended June 30, 2005, we raised $80.5 million from various debt and equity financings, repaid $26.5 million of outstanding senior notes and expended approximately $30.5 million in cash on natural gas and oil properties. At June 30, 2005, approximately $13.3 million remained in available cash for future capital commitments.

On June 17, 2005, the Company completed the private placement of $63.0 million of senior secured notes bearing interest at three month LIBOR plus 6%. The notes mature on June 18, 2010. We have the right, exercisable quarterly during the period from August 17, 2005 to June 16, 2007, to require the original purchaser of the senior secured notes to purchase additional notes in an amount limited to an aggregate of $20.0 million in principal, provided that we comply with certain financial and other covenants.

Concurrently with the private placement of senior secured notes, we closed the acquisition of additional leasehold and working interest properties from Geostar in the Hilltop area of East Texas and in the Powder River Basin of Wyoming and Montana. We paid a total of $68.5 million for the interests acquired from Geostar consisting of $30.5 million in cash, 1,650,133 common shares valued at CDN$4.50 per share and $32.0 million in unsecured subordinated notes maturing on January 31, 2006.

On June 30, 2005, we completed a private placement of 6,617,736 common shares at CDN$3.31 per share. The estimated net proceeds from this placement were $16.4 million (CDN$20.5 million), after deducting placement fees and expenses.

Index to Financial Statements

We continually evaluate our capital needs and compare them to our capital resources. To execute our operational plans, particularly our drilling plans in East Texas, additional funds will be needed for acreage acquisition, seismic and other geologic analysis, drilling, undertaking completion activities and for general corporate purposes. Our current budgeted capital expenditures for the next twelve months is approximately $40.0 million. 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 and expenditures associated with our projected drilling and development activities. We expect to fund these expenditures from internally generated cash flow, cash on hand, the issuance of additional senior secured notes or the issuance of additional 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 business plan. During 2004 and continuing into 2005, the availability of capital for companies in the energy industry has been high. Given the continued forecasts for high natural gas and oil prices, we believe that sufficient capital will be available to execute our business and operational plans.

We are highly dependent upon natural gas pricing. A material decrease in current and projected natural gas prices could impair our ability to raise additional capital on acceptable terms and result in a financial covenant default under the senior secured notes. Likewise, a material decrease in current and projected natural gas prices could also impact our ability to divest ourselves of certain non-core assets. This could impact our ability to fund future activities. Under the terms of our senior secured notes, the proceeds from asset sales must first be offered to the holders of the senior secured notes as repayment of outstanding debt.

We currently have no natural gas price financial instruments or hedges in place. Similarly, we have no financial derivatives. Our natural gas marketing contracts use “spot” market prices. Given the uncertainty of the timing and volumes of our natural gas production this year, we do not currently plan to enter into any long term fixed-price natural gas contracts, swap or hedge positions, other gas financial instruments or financial derivatives in 2005. Further, the senior secured notes covenants restrict us from hedging more than 50% of future production.

We have no off-balance sheet arrangements and have no plans to enter into any at this time.

Significant Accounting Policies

The consolidated financial statements of the Company are in U.S. dollars unless otherwise noted and have been prepared by management in accordance with generally accepted accounting principles (“GAAP”) in the United States. The preparation of consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The consolidated financial statements have, in management’s opinion, been properly prepared using careful judgment with reasonable limits of materiality and within the framework of the significant accounting policies summarized below:

Consolidation. The consolidated financial statements include the accounts of the Company and the consolidated accounts of all its subsidiaries. The entities included in these consolidated accounts are 100% owned unless specified: New Energy West Corporation; 616694 Alberta Ltd.; Monterey Resources, Inc.; New Energy West (U.S.A.) Corporation; 1075191 Ontario Ltd., First Sourcenergy Wyoming, Inc; First Source Development, Inc; First Texas Development, Inc.; First Source Gas LP; Bossier Basin LLC; First Sourcenergy Group, Inc.; First Sourcenergy Kansas, Inc.; First Sourcenergy Victoria, Inc; Squaw Creek, Inc.; First Appalachian Development, Inc.; and Oil and Gas Services Inc. All significant intercompany accounts and transactions have been eliminated.

Furniture, equipment and other. Furniture, equipment and other are carried at historical cost and are amortized over various periods ranging from three to seven years on a straight-line basis.

Natural gas and oil properties. The Company follows the full cost method of accounting for natural gas and oil operations pursuant to SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing

Index to Financial Statements

Companies” whereby all costs of exploring for and developing natural gas and oil reserves are initially capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities.

Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves as determined by independent petroleum engineers, converting one barrel of oil to one thousand cubic feet natural gas equivalents (Mcfe) by multiplying barrels by a factor of 6. The percentage of total reserve volumes produced during the year is multiplied by the net capitalized investment plus future development costs in those reserves (the “depletable base”).

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.

Reserves, future production profiles, and net cash flows are estimated by an independent professional reservoir engineering firm. While Gastar has hired a qualified reservoir engineering firm, its estimates are inherently uncertain, involve numerous assumptions that may not be realized, and predict asset values that may not be indicative of the true market value of the assets evaluated. As a result of the inherent uncertainties and changing technical and economic assumptions, reserve estimates are subject to revisions that can materially impact our results.

In applying the full cost method, the Company performs a ceiling test on properties which compares the net cost of natural gas and oil properties (“net cost”), which is equal to the unamortized cost of natural gas and oil properties less any deferred income taxes related to those properties with the calculated ceiling. The calculated ceiling (“ceiling”) is equal to the sum of the estimated discounted future net revenues from production of proved reserves as determined by an independent engineer, generally using prices in effect at the end of the period held flat for the life of production excluding the estimated abandonment cost for properties with asset retirement obligations recorded on the balance sheet and including the effect of derivative contracts that qualify as cash flow hedges, discounted at 10%, the lower of cost or estimated fair value of unproved properties included in the costs being amortized and the cost of properties not being amortized less the income tax effects. If the net cost exceeds the ceiling, an impairment loss will be determined. The impairment loss is measured as the amount by which the net cost exceeds the ceiling and is shown as a reduction in natural gas and oil properties as additional depletion. Proceeds from a sale of natural gas and oil properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion or amortization.

Mineral resource properties. All acquisition, exploration and related direct and indirect overhead expenditures are expensed. The costs relating to a property abandoned are written off when the decision to abandon is made.

Revenue recognition. Revenue is recognized on delivery to customers pursuant to the sales method net of royalties.

Financial instruments. The Company carries various forms of financial instruments. Unless otherwise indicated, it is management’s opinion that the Company is not exposed to significant interest, currency or credit risks arising from these financial instruments. The fair values of these financial instruments approximate their carrying values, unless otherwise noted.

Foreign exchange. Foreign currency balances of the parent company and non-monetary assets and liabilities are translated at the rates of exchange on the particular transaction date. Monetary assets and liabilities denominated in foreign currencies that remain outstanding at the balance sheet date are translated at period end exchange rates with resulting gains (losses) being recognized in the period. The accounts of all active subsidiaries are maintained in US dollars.

Index to Financial Statements

Deferred income taxes. The liability method of tax allocations is used, based on differences between financial reporting and tax bases of assets and liabilities. No future tax asset has been recorded as it is uncertain whether the Company will be able to realize this benefit.

Reporting currency. A majority of the Company’s operations are conducted by its U.S. subsidiaries in U.S. dollars. The operations outside of the U.S. are primarily natural gas and oil property development in Australia, which are conducted in Australian dollars. Limited operations are conducted in Canadian dollars. The Company reports its operations in U.S. dollars, its functional currency.

Treasury stock method. Basic earnings per common share is computed by dividing earnings by the weighted average number of common shares outstanding for the period. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments.

Cash and cash equivalents. Cash and cash equivalents include short term investments, such as money market deposits or highly liquid debt instruments, with a maturity of three months or less when purchased. We maintain our cash in bank deposit accounts, which, at times, may exceed federally insured limits. We have not experienced any losses in such accounts and believe we are not exposed to any significant risk of loss.

Stock-based compensation. The Company reports compensation expense for stock options granted to employees, officers and directors using the fair value method. Fair values are determined using the Black-Scholes model. Compensation costs are recorded over the vesting period.

Deferred financing costs. Deferred financing costs include expenses of debt financings undertaken by the Company including commissions, legal fees, value attributed to warrants issued in conjunction with the financing and other direct costs of the financing. Using the interest method, the deferred financing costs are amortized over the term of the related debt.

Accretion on convertible debentures. Using the interest method, the equity component of the convertible debentures is amortized over the term of the related debt.

Asset retirement obligation. Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations (“SFAS No. 143”) using a cumulative effect approach to recognize transition amounts for asset retirement obligations, asset retirement costs and accumulated depreciation. Asset retirement costs and liabilities associated with site restoration and abandonment of tangible long-lived assets are initially measured at a fair value, which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash flows. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost are recognized in the results of operations.

Joint venture operations. The majority of the Company’s natural gas and oil exploration activities are conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities.

Reclassification. Certain information provided for the prior year has been reclassified to conform to the presentation adopted in 2005.

Goodwill. On January 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). Under SFAS 142, goodwill and indefinite-lived intangible assets are no longer amortized but are reviewed annually (or more frequently if impairment indicators arise) for impairment. Separable

Index to Financial Statements

intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives (but with no maximum life). The Company has no goodwill, so adoption of this standard had no impact on our financial position or results of operations.

Unaudited periods. The financial information with respect to the three months ended March 31, 2005 and 2004 is unaudited. In the opinion of management, this information contains all adjustments, consisting only of normal recurring accruals, necessary for a fair presentation of the results for the periods presented. The results of operations for interim periods are not necessarily indicative of the results of operations for the full fiscal years.

Industry segment and geographic information. The Company operates in one industry segment, which is the exploration, development and production of natural gas and crude oil. The Company’s operational activities are conducted in the United States and Australia with only the United States currently having revenue generating operating results.

New accounting policies. In December of 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS 123R, “Share Based Payments” which addresses the accounting for transactions in which an entity exchanges its equity instruments for goods and services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. This statement is a revision of FASB No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”). This statement supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees”. Among other things, this statement requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. That cost is recognized over the period during which an employee is required to provide service in exchange for the award – the requisite service period (usually the vesting period). This statement is to be applied as of the beginning of the first interim or annual period that begins after June 15, 2005, but earlier adoption is encouraged. Because the Company has disclosed pro-forma fair based value amounts in accordance with the original SFAS 123, it allows a company to adopt using a modified prospective approach. This will require the Company to recognize in the third quarter of 2005, compensation expense for options granted after June 15, 2005 and compensation expense for awards not yet vested but still outstanding.

In December of 2004, FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets – An Amendment of APB Opinion No. 29” (“SFAS No. 153”). The guidance in APB Opinion No. 29, “Accounting for Nonmonetary Transactions” (“APB Opinion No. 29”) is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in that APB Opinion No. 29; however, included certain exceptions to that principle. This Statement amends APB Opinion No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Earlier application is permitted for nonmonetary asset exchanges occurring in fiscal periods beginning after the date this Statement is issued. The provisions of this Statement shall be applied prospectively. The adoption of SFAS No. 153 did not have any impact on the Company’s financial statements.

Quantitative and Qualitative Disclosure about Market Risk

Commodity Risk. Our major commodity price risk exposure is to the prices received for our natural gas production. Realized commodity prices received for our production are the spot prices applicable to natural gas in the region produced. Prices received for natural gas are volatile and unpredictable and are beyond our control. For the year ended December 31, 2004, a 10% change in the prices received for natural gas production would have had an approximate $600,000 impact on our revenues.

Interest Rate Risk. The carrying value of our debt approximates fair value. At March 31, 2005, we had approximately $58.0 million of long term debt, all of which was fixed rate. Fluctuations in interest rates have no

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impact on interest expense. In June 2005, we issued $63.0 million of senior secured notes that bear interest at three-month LIBOR plus 6%. A 10% fluctuation in interest rates would have an approximate $189,000 impact on annual interest expense.

Currency Translation Risk. Because our revenues and expenses are primarily in U.S. dollars, we have little exposure to currency translation risk, and, therefore, we have no plans in the foreseeable future to implement hedges or financial instruments to manage international currency changes.

Contractual Obligations and Contingencies

Our contractual obligations as of December 31, 2004 consisted of the following:


	For the Years Ended December 31,
	2005		2006-2008		2009-2010		After 2010		Total
	(in thousands)
Long term debt	$	—	$	26,483	$	33,250	$	—	$	59,733
Operating leases		—		532		532		—		1,064

Total	$	—	$	27,015	$	33,782	$	—	$	60,797

Off-Balance Sheet Arrangements

As of June 30, 2005, we had no off-balance sheet arrangements. We have no plans to enter into any off-balance sheet arrangements in the foreseeable future.

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BUSINESS

Our Business

We are an independent energy company engaged in the exploration, development and production of natural gas and oil in the United States and Australia. Our principal business activities include the identification, acquisition, and subsequent exploration and development of natural gas and oil properties. Our emphasis is on prospective deep structures identified through seismic and other analytical techniques as well as unconventional natural gas reserves, such as coal bed methane. We seek to reduce exploration risk and financial exposure by acquiring properties that have wells previously drilled in close proximity or into the targeted geologic horizons, joint venturing with knowledgeable industry partners or by farming out acreage to other industry participants on terms that reduce our economic risk to levels deemed appropriate. Our current areas for natural gas or oil activities are:

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Deep Bossier play in East Texas;

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Powder River Basin in Wyoming and Montana;

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Gunnedah Basin in New South Wales, Australia;

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Gippsland Basin in Victoria, Australia;

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Appalachian Basin in West Virginia;

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San Joaquin Basin in California; and

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Cherokee Basin in Southeast Kansas.

We currently are pursuing conventional natural gas exploration in the Deep Bossier play in the Hilltop area in East Texas and the Appalachian Basin in West Virginia. In exploring for conventional hydrocarbons, we utilize advanced geophysics and geologic technologies to identify high potential natural gas prospects. As of June 30, 2005, we had leases on approximately 53,100 gross acres (34,000 net) in Texas and approximately 26,700 gross acres (13,300 net) in Appalachia. For the six months ended June 30, 2005, our daily production from the Hilltop area averaged approximately 6.9 MMcfed, and from the Appalachian Basin, it averaged 0.1 MMcfed.

In our coal bed methane, or CBM, projects, we use advanced technologies to assist us in developing commercial natural gas production from known coal beds. Our primary CBM properties are in the United States in the Powder River Basin and in the Gunnedah and Gippsland Basins of Australia. As of June 30, 2005, our acreage position in the Powder River Basin was approximately 56,800 gross acres (21,900 net), and our Australian acreage totaled approximately 3.4 million gross acres (2.0 million net). For the six months ended June 30, 2005, our average daily production from our CBM properties in the Powder River Basin was approximately 1.9 MMcfed. Exploration and long term production testing on our Australian CBM properties is currently underway. Thus, we currently have no natural gas sales from our Australian CBM properties.

Our Strategy

Management believes that:

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Natural gas is an environmentally friendly fuel that will be increasingly valued in the United States and Australia;

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Conventional natural gas exploration exposes us to potentially large natural gas reserves and significant increases in shareholder value;

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CBM projects provide us with lower risk exposure to long-lived natural gas production and reserves;

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We have made a significant natural gas discovery in the Deep Bossier play in the Hilltop area of East Texas that will require additional exploration and development;

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•

We have the ability to assemble the technical and commercial and resources needed to pursue these potential projects; and

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Our successful development of one or more large potential natural gas projects will create substantial shareholder value.

Based on these beliefs, we have pursued a strategy that includes:

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Accelerating exploration and development drilling on our Deep Bossier play in East Texas;

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Combining lower risk CBM projects, such as the Powder River Basin and Australia, with higher risk conventional natural gas exploration;

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Assembling a portfolio of high-potential natural gas exploration and development projects in the East Texas and Appalachian Basins; and

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Natural Gas and Oil Operations

The following provides an overview of our significant natural gas and oil projects. While actively pursuing specific exploration and exploitation activities in each of the following areas, we are continually reviewing additional opportunities. There is no assurance that new drilling opportunities will continue to be identified or that any new drilling opportunities will be successful if drilled.

Geostar Acquisition

Concurrently with the private placement of senior secured notes on June 17, 2005, we closed the acquisition from Geostar of additional leasehold and working interest properties in the Hilltop area of East Texas and in the Powder River Basin of Wyoming and Montana. We paid a total of $68.5 million for the interests acquired from Geostar consisting of $30.5 million in cash, 1,650,133 common shares valued at CDN$4.50 per share and $32.0 million in unsecured subordinated notes maturing on January 31, 2006. The acquisition increased our working interest position in the Hilltop area from an average of over 70% to an average of over 90% and gave us operational control of the properties. The acquisition of additional Powder River Basin interests increased our average working interest position from approximately 17% to approximately 38% in properties currently being developed through an existing joint venture.

Hilltop Area, East Texas

General. As of June 30, 2005, we have approximately 53,100 gross acres (34,000 net) in the Deep Bossier play in the Hilltop area, located approximately midway between Dallas and Houston in East Texas. Wells in this area target multiple potentially productive natural gas geologic horizons. Deep Bossier sand wells are typically characterized by high initial production, significant decline rates and long-lived reserves. The development of effective hydraulic formation fracturing, or “frac”, techniques has allowed operators to develop significant

Index to Financial Statements

reserves in the Deep Bossier sand intervals. Our acreage is located in an area within the East Texas Basin where the Deep Bossier sand is encountered at greater depths with possibly thicker pay zones than the typical Deep Bossier sand development that has been experienced by other industry participants.

Geology. The East Texas Basin is characterized by numerous shallow and deeper productive horizons. The basin has been the site of natural gas and oil activity since the earliest days of the U.S. natural gas and oil industry. The Deep Bossier sand formation that we are targeting was not considered prospective until our activities together with the drilling of a nearby well ignited a high level of interest in this formation. To our knowledge, prior to our initial drilling activities in 2001, no wells had been drilled specifically for Deep Bossier sand production in East Texas. Our geoscientists developed the Deep Bossier sand prospect focusing on two deep wells drilled in the early 1980s. Those wells encountered over-pressured, gas-charged reservoirs in the Bossier shale section and were unable to reach the intended targets. Our geoscientists formulated a depositional model to explain the presence of these high-quality sands in an area previously believed to be too remote from the traditional sand sources for the East Texas Basin. We believe that the wells drilled to date are, in general, supporting this depositional model.

Gas Transportation. Given the high level of traditional natural gas and oil activities in the East Texas Basin, the area has extensive natural gas pipeline infrastructure in place. In July 2004, a new one Bcf per day natural gas transmission pipeline was constructed approximately three miles from our initial drilling activities. We have contracted for an initial 50.0 MMcfd of capacity and are negotiating an increase in that amount. Our current production from the Hilltop area is transported to the Katy Hub in Katy, Texas, where numerous parties are available to purchase the natural gas.

Activities. In 2001, we participated in the 21,000 foot Belin Trust A-1 well. In January 2003, Geostar took over as operator of the Belin Trust A-1 well. Geostar attempted a completion in a Deep Bossier sand (approximately 18,512 feet to 18,610 feet) and was encouraged by the initial test results. A fracture stimulation and other downhole treatment techniques were performed. The well briefly tested pipeline quality natural gas at short term rates up to 5 MMcfd before experiencing mechanical casing problems. The well was ultimately plugged and abandoned due to safety concerns.

Due to the encouraging results from the Belin Trust A-1 well and the results of several earlier wells drilled in the area, we announced in September 2003, that we had begun site operations on the F-K #1 well in Leon County, Texas. As a 75% working interest owner, we drilled the F-K #1 well to a projected depth of 19,175 feet. A 20.0 MMcfd natural gas processing plant was constructed at the site, and, in September 2004, the F-K #1 well began production with initial production rates of 15.0 MMcfd (8.5 MMcfd net). We now have a 98% working interest in the F-K #1 well as a result of the Geostar acquisition. Current production is approximately 6.4 MMcfd (4.8 MMcfd net).

The Cheney #1 well was drilled in the Hilltop area to test the Deep Bossier sand encountered in the F-K #1 well. This well is approximately one mile north of the F-K #1 well. The Cheney #1 well encountered approximately 400 net feet of potential pay based on natural gas shows while drilling and on logs. The well commenced production in mid-February 2005 at an initial rate of approximately 7.0 MMcfd (4.0 MMcfd). As a result of the Geostar acquisition, our working interest in the Cheney #1 increased from 75% to 98%. Current daily production is approximately 1.0 MMcfd (0.8 MMcfd net). We believe that our initial fracture stimulation of the primary pay zone in the Cheney #1 well was not effective, and we are planning to re-stimulate this well in August 2005. A 20.0 MMcfd natural gas processing plant has been constructed on the Cheney #1 well site that processes production from the Cheney #1 and the Lone Oak Ranch #1 wells. We built a pipeline connecting the F-K #1 well and the Cheney #1 well site to an existing pipeline system that moves production to a major natural gas hub at Katy, Texas.

In September 2004, as a 73% working interest owner, we announced that our third Deep Bossier sand well in East Texas, the Lone Oak Ranch #1 well, had begun drilling. The well is located approximately three miles

Index to Financial Statements

north northwest of the F-K #1 well and approximately two miles northwest of the Cheney #1 well. The Lone Oak Ranch #1 well was drilled to target expanded Upper and Middle Bossier sections and will also test for the deeper Bossier sand encountered on the Hilltop structure in the F-K #1 and Belin Trust #1-A wells. We now have a 98% working interest in the Lone Oak Ranch #1 well as a result of the Geostar acquisition. An unrelated private exploration and production company has a 25% after payout back-in interest in the Lone Oak Ranch #1 well. As a result of the Geostar acquisition, we will hold an after payout working interest of 69% in the Lone Oak Ranch #1 well. In addition to exploring additional acreage in the Hilltop area, this well completed our obligations to earn a 56.25% working interest (approximately 75% post-Geostar acquisition) in approximately 8,000 gross acres in the Hilltop area of East Texas, including acreage that directly offsets the F-K #1 well. Current daily production is approximately 5.7 MMcfd (4.2 MMcfd net).

We began drilling the Greer #1 well, our fourth Deep Bossier sand well in the Hilltop area in January 2005. The Greer #1 well is located approximately one mile from the F-K #1 well. We drilled the Greer #1 well to a total depth of 17,800 feet and, based on gas shows during drilling and electric logs, the well encountered approximately 57 net feet of apparent pay. As a result of the Geostar acquisition, we increased our working interest in this well from 73% to 98%. The well commenced production in July 2005 at an initial gross sales rate of approximately 5.0 MMcfd (3.9 MMcfd net).

Drilling commenced in February 2005 on the Fridkin-Kaufman #2, or F-K #2, well to a total depth of 18,700 feet. Based on electric logs, the well encountered approximately 74 net feet of apparent pay in the Bossier lower “K” sand below 18,000 feet. The well encountered over 120 feet of indicated pay in the shallower Travis Peak formation. The well is located approximately 2,200 feet from the F-K #1 well. Planned completion activities are expected to take approximately 60 days and, if successful, initial production is expected by mid-September 2005. As a result of the Geostar acquisition, our working interest in the F-K #2 increased from 78% to 100%.

We are currently conducting extensive seismic analysis of the available Hilltop seismic data and continue to refine our geologic model of the area. We have also begun permitting a large scale 3-D seismic survey that will cover the majority of our acreage in the Hilltop area in order to better define and understand the complex geology associated with the deposition of the Deep Bossier sand in the area. The 3-D survey will also evaluate the Lone Oak Ranch area and the numerous locations similar to other Bossier play wells. We are also planning the drilling of additional deep wells, and we plan to continue to acquire new leases in the area.

Appalachian Basin, West Virginia

General. The Appalachian Basin is a proven hydrocarbon basin with substantial production history. The well developed infrastructure and proximity to major natural gas markets in this area result in gas prices generally exceeding Henry Hub gas prices, the standard for pricing NYMEX natural gas contracts. While numerous potential hydrocarbon horizons exist, we are focusing our West Virginia plans primarily on three potentially productive horizons: shallow conventional sands; the deep Trenton-Black River and fractured medium depth Devonian shales.

Shallow Conventional Gas. We have participated in 11 pilot wells drilled into shallow conventional gas sands. The Venango (Upper Devonian age) hydrocarbon horizon, including the primary targets of the Fifty-foot Sand, the Fifth Sand and the Gordon Sand, is a multiple horizon sand located at depths of generally less than 5,000 feet. The drilling of these horizons is relatively fast and inexpensive.

Trenton–Black River Deep Gas. The Trenton-Black River play was discovered in western New York where natural gas wells drilled to the Trenton-Black River formations produced at reported initial rates of

Index to Financial Statements

approximately 5.0 to 8.0 MMcfd. The play was extended to southern central West Virginia when Trenton-Black River wells were drilled in the Roane County Cottontree Field that had reported estimated absolute open flows ranging from 50 MMcfd to over 200 MMcfd during short term testing and recoverable reserves estimated at 8 to 10 Bcf per well.

The deep Trenton-Black River prospective formations and other deep geologic horizons can only be identified through the use of acquired or reprocessed seismic data. Geostar, the operator of the properties, has acquired and reprocessed available 2-D seismic data as well as acquired additional proprietary 2-D seismic data to identify these deep features. We control significant lease positions over several of these seismically defined features.

Fractured Devonian Shales. Since the beginning of Appalachian natural gas production, natural gas has been produced from various shale formations. Devonian shales are generally considered to be an unconventional natural gas reservoir. We are combining experience gained from CBM production with our seismic acquisition and processing analysis to attempt to determine areas where naturally occurring fracture systems potentially increase shale well productivity.

Activities. As part of our ongoing business activities, we are constantly reassessing the technical and commercial potential of our exploration acreage. As of June 30, 2005, we had approximately 26,700 gross acres (13,300 net) in the Appalachain Basin in West Virginia. We have acquired a small working interests in the Cross #1 well and the Hammack #1 well to increase our understanding of Trenton-Black River geology and geophysics. We have a 7.0% working interest in the Cross #1 well in the Cottontree Field located in Roane County, West Virginia and a 2.0% working interest in the Hammack #1 well in Roane County. The Cross #1 well is selling approximately 900 Mcfd (gross), and the Hammack #1 encountered no commercial natural gas.

East Lost Hills Field, San Joaquin Basin, California

General. The San Joaquin Basin of California is one of the most prolific hydrocarbon producing basins in the continental United States. The 14,000 square mile basin has produced an estimated 13 billion BOE and contains 25 fields classified as giant fields, each with cumulative production to date of more than 100 million barrels of oil equivalent.

Activities. On November 23, 1998, the Berkley-Bellevue ELH-1 well was drilled at a depth of 17,600 feet on the East Lost Hills structure. It blew out and ignited when it encountered high-pressure gas in the Deep Temblor horizon. It was reported that the blow-out well produced a significant amount of gas and liquids before it was eventually brought under control. While the Berkley-Bellevue ELH-1 well blew out when it encountered high-pressure gas in the Deep Temblor horizon, additional wells have been unsuccessful.

Our California properties are located in the East Lost Hills field in Kern County, California. The ELH structure has an elongated oval shape that has a northwest to southeast orientation. Our properties are generally located along the northwest end of the ELH structure, where we have approximately 3,000 gross acres (3,000 net) on or near the ELH structure. We have no definitive plans to drill on our East Lost Hills acreage at this time; however, we are planning to evaluate the potential for shallower prospective formations on these leases.

Coal Bed Methane

Our acreage positions in the Powder River Basin and in Australia are primarily CBM plays. CBM is methane gas that is formed and stored in coal beds. The presence of methane in coal seams has been known since the mining of coal began. Until recently, CBM was considered a safety problem, and coal had to be “degasified” before subsurface coal mining could occur. In the last two decades, however, the natural gas industry has dramatically improved its technical understanding of CBM production techniques and CBM has come to be viewed as a major source of low cost methane.

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CBM production is dissimilar to conventional natural gas production in several notable ways. Coal seams produce nearly pure methane gas while conventional natural gas wells normally produce natural gas that contains small portions of ethane, propane and other heavier hydrocarbon gases. Methane normally constitutes more than 90% of the total gases in the production from conventional natural gas wells. Also, because coal beds often contain substantial amounts of water, it is first necessary to produce water to lower the reservoir pressure to allow the CBM to be produced. Producing and properly handling the water from the coal beds is an important part of CBM production. Once produced, CBM is dried to remove any residual moisture, compressed to pipeline pressures and ultimately transported in the same interstate pipelines as natural gas from conventional natural gas fields. CBM is also sold to the same consumers and used in the same applications as natural gas produced from conventional wells.

Since the late 1970s, CBM has been produced commercially by drilling conventional well bores into coal beds. The first commercial CBM fields were developed in the high rank bituminous hard coal beds of Alabama, the Appalachian Mountains of Pennsylvania, Virginia, West Virginia, the San Juan Basin of Colorado and New Mexico. Limited commercial CBM production was established in 1989 in the lower rank, sub-bituminous soft coals of the Powder River Basin of Wyoming, CBM production from the Powder River Basin has increased substantially since that date.

CBM plays differ from conventional natural gas plays in several significant ways. The large size of coal beds tends to reduce geologic risks while the generally shallow depths of the coals can result in simple wells with relatively low drilling costs. The combination of large CBM deposits, relatively low geologic risk and low drilling costs make CBM plays some of the most attractive in the United States. Although the actual finding and development costs vary for each individual gas field, significant technical strides have been made in lowering CBM costs.

We are actively developing CBM properties in the Powder River Basin of Wyoming. We are also investigating CBM development plans in the Appalachian Basin of West Virginia, on Petroleum Exploration License 238, or PEL 238, in the Gunnedah Basin in New South Wales, Australia and in the Gippsland Basin in Victoria, Australia.

Powder River Basin, Wyoming and Montana

General. The Powder River Basin encompasses approximately 26,000 square miles of eastern Wyoming and southeastern Montana. The Wyoming Powder River Basin has been an important natural gas and oil producing area for nearly 100 years. Likewise, Wyoming has been a top producer of low-sulfur soft coal for many years. Only recently has a connection been made between the large coal reserves of the basin and natural gas production. Beginning in about 1989, Powder River Basin CBM development began in earnest and has increased dramatically in recent years. The drilling activity began about 40 miles south of Gillette, Wyoming and extended northward along the east flank of the basin and westward into the basin. Generally, CBM wells are shallow and less costly than conventional natural gas wells. Because of the widespread nature of multiple coal horizons, the geologic success rates reported by some operators in the Powder River Basin have been high. Due to these and other factors, the Powder River Basin CBM play has developed into one of the most active drilling areas in the United States. However, there is no assurance that we will achieve comparable cost or similar success rates.

Geology. Coal in the Powder River Basin is found in the relatively shallow Paleocene Fort Union Formation. This coal forms some of the thickest known coal seams in North America. During the 1960s and 1970s, exploration wells being drilled to deeper conventional natural target horizons encountered this coal and commonly experienced gas flows from the shallow coal formations. These wells generally yielded large volumes of water and little commercial natural gas. In some cases, blowouts occurred due to unexpected natural gas flows from the shallow coal zones.

Excellent micro-permeability helps explain why natural gas from the Powder River Basin coal is readily produced without costly artificial stimulation. Microscopic pathways facilitate the movement of CBM to open

Index to Financial Statements

fractures, and through these fractures, CBM finds its way to the borehole. Fracturing of the coals is apparently common throughout the Powder River Basin. This is exemplified by the large and growing area of CBM production and the large number of natural gas flows from water wells drilled into or through coal formations. The fracturing of the coal beds is critical since it is the fractures in coal that provide pathways for natural gas migration and production. Gas produced from Powder River Basin coals generally has very high methane content, usually requiring no treatment to remove carbon dioxide or nitrogen.

Drilling Techniques. One of the main reasons for the rapid pace of activity in the Powder River Basin is the low cost of drilling to shallow depths, generally less than 1,200 feet, and the fact that the coal there normally does not require expensive fracture treatments to produce at economic rates. The standard procedure has been to drill to just above a coal formation, set casing, then air drill into the coal, under-ream the hole, circulate out cuttings, set a pump or install gas lift if water volumes dictate, and place the well on production. CBM wells are drilled in “units” or projects, with each well in the unit connected to a low-pressure gathering pipeline. The gathering line delivers produced natural gas and water to a central facility where water is disposed of and natural gas is compressed and metered for delivery through a sales line to a main gas transport pipeline. The water production from CBM wells varies substantially. Although subject to regulatory review and approval, produced water is usually fresh and has generally been disposed of in holding ponds and surface streams. Other disposal techniques, which are somewhat more expensive, such as re-injection into non-producing formations, have also been used to dispose produced water. Gathering and processing costs vary by well location, system design and take-away capacity. Properties that are close to major pipelines should have substantially lower gathering costs than more remote properties.

CBM Production. The typical CBM well in the Powder River Basin initially produces significant quantities of water. As the water is produced, natural gas production also begins slowly. Typically, after a considerable amount of water is produced over a three to six-month period or longer, gas production increases and water production decreases. In some cases, wells do not produce any significant amounts of water and begin producing gas immediately. This free gas is produced from fractures in the coal that are attributable to subtle structural folding or compaction of coals after they were deposited. As the development expands, the productive area increases as water is produced from these areas. Water production can also be reduced near the edges of the basin, especially near massive open pit coal mines. These shallow coals near the outcrops appear to be partially de-watered naturally due to the extensive surface mining and its associated water production.

Gas Transportation. Of critical importance to the success of a CBM project in the Powder River Basin is natural gas transportation to market. Major gas pipelines have been built into the basin to transport CBM to major interstate gas markets. The Thunder Creek, Fort Union, Bighorn and Western Gas Resources pipelines are the major pipelines flowing out of the south end of the basin. The Williston Basin Interstate pipeline runs north to Montana, then east to North Dakota, eventually connecting to the Northern Border pipeline and eastern markets. Western Gas Resources’ pipelines have access to both the south and north flowing pipelines. Each of our Powder River Basin properties has access to one or several of these pipelines. Additional pipeline capacity to both the north and south has been proposed to be built.

Gas sales prices vary with the market, but historically have been based on the prices posted by Colorado Interstate Gas. While prices generally track this index, when transportation capacity is fully utilized, Powder River Basin gas prices can be substantially depressed, which happened in the summer of 2002.

Activities. We now own an approximate 38% average working interest in 56,800 gross acres (21,900 net) in the Powder River Basin of Wyoming following the Geostar acquisition. Our main focus of activity is the Squaw Creek and adjacent areas, notably the Ring of Fire field. We currently have approximately 282 CBM wells producing in the Basin.

In 2003, we closed a Powder River Basin Earn-In Joint Venture with a third party who paid approximately $6.7 million and made a spending commitment of $14.5 million and became operator. We assigned the operator

Index to Financial Statements

66% of our interest in all of our existing producing and non-producing leases within the area of mutual interest. Under the agreement, the operator received 60% of all pre-tax cash flow as defined in the agreement until May 2004 when it recovered the $14.5 million spending commitment amount and acquired an interest equal to 50% of our interests. We are 50/50 joint venture partners with the operator for new CBM exploration and development activity within the AMI. In the third quarter of 2004, we exercised our option to invest additional funds to maintain our working interest ownership in any wells drilled after the spending commitment was met and will continue to invest in the Powder River Basin.

In 2004, approximately 117 wells were drilled under the joint venture. Of the new wells drilled, approximately 112 were on production in the second quarter of 2005. Pinnacle continues to drill under the joint venture agreement. We have chosen to fund our working interest ownership in any wells drilled after the spending commitment was met.

We have drilled 17 pilot test CBM wells in the Fence Creek area, but the project area is not currently connected to a natural gas pipeline. The operator has informed our management that it is currently evaluating potential natural gas gathering infrastructure options to allow development of the Fence Creek area.

Gunnedah Basin, New South Wales, Australia

General. PEL 238 is an approximately 2.0 million gross acre (1.0 million net acre) CBM property located approximately 250 miles northwest of Sydney, Australia, in the Gunnedah Basin of New South Wales. The Gunnedah Basin’s characteristics include porous permeable quartzose sandstones at several stratigraphic levels that are adjacent to mature organic reservoir rocks that are age equivalents of producing formations in the other producing regions of Eastern Australia. CBM potential is also high, as previous wells and coreholes have penetrated aggregate coal thickness of up to 250 feet.

The geology of the PEL 238 area is characterized by buried ridges and troughs and coal gas accumulations considered to be associated with structurally high positions. Coal was deposited throughout the Lower Permian in various parts of the Gunnedah Basin. There are over 500 miles of seismic data available over the PEL 238 area. The coal is dull, blocky and relatively uncleated.

The primary coal objective of the PEL 238 area is Maules Creek at depths of 2,500 to 3,000 feet, and the secondary coal objective is the Hoskisson coal at depths of 1,500 to 2,000 feet. The Maules Creek coal is Permian age coals. In the PEL 238 area, they have a vitrinite reflectance of about 0.7 and are slightly overpressured with a gradient of 0.48 psi per foot. The ashfree gas content of this coal is in the range of 400 to over 500 standard cubic feet per ton of coal. The Maules Creek coal is a closed coal system that is not mined in the area and thus should not be subject to rapid re-charge of the hydro system. The Hoskisson coals have not been tested. All tests to date have been in the Maules Creek area. The Hoskisson coal gas content is in the range of 200 to 300 standard cubic feet per ton of coal. The Hoskisson coal outcrop and is mined to the east of the PEL 238 area.

The CBM play in the Gunnedah Basin was initiated in 1963 with the Bohena #1 discovery well. The Australian Department of Mines and Resources has drilled over 200 core wells in the eastern portions of PEL 238 and outside the concession area that are useful in delineating the coals.

Activities. In 2003, we were the 100% coalbed methane working interest owner on the approximately 2.0 million acre PEL 238 concession. In 2004, we entered into a joint venture and reduced our CBM ownership to 70%. The New South Wales government has drilled over 18 conventional and CBM wells and over 200 coal core holes within PEL 238. Several PEL 238 CBM wells have demonstrated brief periods of gas production ranging from 200 to 400 Mcfd. However, these wells were not able to sustain these rates, potentially from formation damage caused while drilling. The low sustained gas and water production rates may be due in part, to

Index to Financial Statements

suboptimal completion techniques. The joint venture is attempting to define the optimum completion technique for the PEL 238 coal that will allow sustained high flow rates to dewater the coal and to support commercially extensive development and tie-ins to surrounding natural gas markets. Additional issues that are being studied include variable carbon dioxide content in the range of 5% to 50% thought to be caused by tertiary volcanics underlying the coal sections in certain areas, correlation of individual coal seams from well to well, variable ash contents, and natural gas marketing issues. Based on these uncertainties, PEL 238 has no proven natural gas reserves.

After taking over the Maules Creek CBM operatorship in 2001, we reworked several CBM wells drilled by the previous operator and established short term production rates that would indicate commercial viability for CBM development. We then equipped the Bohena #3 well with the necessary equipment for a long term production test. Due to extensive well bore damage caused by the previous operator, only a very limited portion of the coals present were able to be reworked. The Bohena #3 well was on continuous production testing from March 2002 to July 2003 and produced at a stabilized rate of approximately 90 Mcfd and 50 Bwd. No other CBM wells were producing in the vicinity of the Bohena #3 well during the timeframe of March 2002 to July 2003 and only very limited de-watering of the coal seams has taken place thus severely limiting gas production. While these test results were not definitive, we continued to believe that development of the CBM resources on the PEL 238 concession could result in substantially higher individual well production.

In the third quarter of 2004, we and our joint venture partners drilled and fracture stimulated two coal seams in two additional vertical CBM wells on PEL 238 to attempt to establish sustained commercial production rates. While we were obligated to drill these wells under a work commitment to New South Wales government to maintain the leases, our joint venture partners have funded the work plan under their earn-in agreement, having increased their ownership interests to 50% during 2005. Management believes that the activities to date have substantially fulfilled the work plan requirements provided in the leases.

Surface facilities were installed and these new vertical CBM wells, and they were placed on production in October 2004. The vertical wells were fracture stimulated using large amounts of sand proppant that was placed in the Upper and Lower Maules Creek coal. The initial and early production flow rates of gas and water indicate that these fracture stimulations were successful. The vertical wells were placed on-line in October 2004 and have produced at very high water rates, indicating good permeability in the coal and an effective stimulation. The wells have also shown early gas production with gas production rising to the anticipated rates for these unconfined wells. The Bohena #9 well initiated production with water rates as high as 400 Bwd and began producing gas after only five weeks of de-watering. After a brief interruption due to the heavy rainfall and flooding, the well has stabilized at approximately 100 Bwd and 70 Mcfd of gas. The Bohena South #1 well began producing in October 2004 at an initial rate of over 1000 Bwd and starting producing gas after only three weeks of de-watering. The Bohena South 31 well is currently producing at rates of approximately 500 Bwd and 60 Mcfd and continues to improve as the fluid level is reduced in the wellbore. The Bibbliwindi #1 well has shown the best performance of the recently drilled wells. That well began producing in October 2004 at approximately 1,000 Bwd and began producing gas immediately. After being shut-in for five months to permit and construct larger water handling facilities, the well was put back on production in June 2005 and is currently producing at a rate of 1,000 Bwd and 17 Mcfd of natural gas.

In addition to these new wells, two older wells were placed back on production. The Bohena #3 and Bohena #7 wells, in the area of the Bohena #9 well, were placed on line in February and March of 2005, respectively. The Bohena #3 well is producing at a rate of 50 Bwd and 100 Mcfd while the Bohena #7 is producing approximately 90 Bwd and 40 Mcfd. The results of all of these wells indicate that commercial gas rates should be achievable with the de-watering of a sufficient area. These conclusions are also supported by independent reservoir modeling matching the early history of the water and gas production to established reservoir simulations. These simulations indicate peak production rates of approximately 1.5 MMcfd per well and recoverable reserves ranging from 1.0 Bcf to 4.5 Bcf per well depending upon well spacing.

Index to Financial Statements

A lateral CBM well was also drilled and completed in the Bohena coal seam to test the productivity of horizontal well technology on PEL 238 coals. Surface facilities were installed and the horizontal well has produced at high initial water rates and has produced gas; however, the water and gas rates have not been sustainable due to damage done to the coal formation during the drilling of the lateral section of the well. The Maules Creek coal is not cleated and as a result, during drilling operations the coal tends to be ground up and create coal fines that appear to damage native permeability in the coal formation. In the vertical wells, this damage is corrected through the fracture stimulations.

If the production performance of these wells continues to confirm the positive results seen recently and in earlier PEL 238 wells, we hope to develop an area sufficient to justify the installation of gathering and transportation assets to serve several local natural gas markets. In order to construct a pipeline for the Bohena area to a local power plant pipeline, it is necessary to file a Development Application, or DA, with the Narrabri Shrine Council, or NSC, and a registration of an easement along the pipeline route. As part of the DA, a Statement of Environmental Effects, or SOEE, will also need to be filed with the NSC. We and our joint venture partners plan to file the DA and SOEE by the end of September 2005. Development consent is anticipated to be granted before the end of 2005.

PEL 238, which includes substantial forest lands, was a part of a New South Wales government-sponsored bioregion study evaluating various land use options for the forests. While there was a wide range of possible land use options proposed, some of which could restrict our access to portions of PEL 238, the final designation of the land within the Bohena project area, covering the planned CBM development area, as Community Conservation Area Zone 4 (forestry, recreation and mineral extraction) should have no material impact on the project. Management and our joint venture partners actively participated in the bioregion process to ensure that our position was well represented and to ensure that our leasehold interests continue to be available for exploration and production.

We and our joint venture partners had committed to spend approximately $1.4 million during the permit year that ended August 2, 2005. The joint venture has spent approximately $2.3 million during the period. The joint venture is currently seeking approval from the New South Wales government, proposing to spend an additional $1.4 million in each of the two work program years ending August 2, 2006 and 2007. The proposed work program calls for the drilling of two CBM well in each of the two years, together with continued geological and geophysical activities and ongoing production management. We will bear between 35% and 50% of these expenditures. PEL 238 will be due for renewal in August 2007. Although there is no assurance that the PEL 238 license will be renewed in 2007, the New South Wales government has typically ruled to extend such licenses.

Gippsland Basin, Victoria, Australia

General. The Gippsland property is located in the onshore portion of Gippsland Basin in Victoria, Australia. The Gippsland Basin is a proven hydrocarbon province that has produced substantial volumes of oil, natural gas and coal. Our project area covers almost all of the onshore part of the Gippsland Basin. The coal in the Gippsland Basin is primarily brown and subbituminous coals, which is similar in composition and age to the coal in the Powder River Basin of Wyoming and Montana. As in the Powder River Basin, very large open pit coal mines are operated in the Gippsland Basin. The mines are located on a relatively small part of the basin near our acreage. Substantial information on the physical properties of the Gippsland Basin coal has been developed due to the extensive mining operations.

Although there has been no organized attempt to date to produce CBM from the Gippsland coal, the stratigraphy and structure of the coal is well known due to extensive core bores, water bores, coal mining operations, petroleum exploration, and other geotechnical evaluations of the coal. While no data on coal gas content and permeability is currently available, natural gas has been measured in the coal and observed coming to the surface during conventional natural gas and oil exploration. The basin has multiple coal sequences at depths of less than 3,000 feet with total coal thicknesses as great as 1,000 feet and with individual seams over several hundred feet thick, which are believed to be some of the thickest brown coal seams in the world. We hope to use CBM techniques developed in the Powder River Basin and other CBM fields to evaluate Gippsland Basin CBM potential.

Index to Financial Statements

Activities. We have an interest in mineral licenses that encompass approximately 1.4 million gross (1.1 million net) acres of Onshore Gippsland Basin in Victoria Australia. We own a 75% working interest in the Gippsland CBM rights and mineral sands rights with Geostar owning the remaining 25% working interest in the CBM and mineral sands rights.

No Gippsland Basin CBM production has been established to date; however, we have recently completed the drilling of two dedicated CBM wells on a site near several conventional wells that penetrated the targeted coal and encountered evidence of both permeability in the coal formation (lost drilling fluids) and the presence of CBM (gas circulated from mud systems after losing drilling fluids to the coal). Both of these new dedicated CBM wells have been drilled using drilling and completion techniques commonly used in the Powder River Basin. Each well was drilled to the top of the coal section and casing was cemented into place. Following the installation of the casing, the wells were then drilled through the coal and, if necessary, the coal are under reamed to create a large diameter cavity in the coal section. We are currently awaiting the availability of service companies to conduct water enhancements of the coal zones, a commonly used stimulation technique in the Powder River Basin that flushes the coal fines created during drilling away from the wellbore in order to create better permeability for the CBM gas to migrate to the wellbore. Upon the completion of the water enhancements, we plan to place the wells on production and begin testing the water and gas production rates in order to estimate recoverable reserves per well.

If the pilot program is successful, access to gas markets is available through three major pipelines that cross our Gippsland properties; one northeast to Sydney, one south to Tasmania, and one west to Melbourne. Additional potential gas markets for Gippsland Basin CBM production include mining projects located near our mineral licenses that potentially could use large amounts of natural gas in value-adding heating and roasting processes. Gas marketing agreements would need to be negotiated with potential customers.

We and our partner were obligated to spend approximately $1.5 million on a work program by April 2004 to maintain our Gippsland Basin leases. Although we did not meet our spending commitment, due in large part to regulatory delays encountered in obtaining certain permits, we met with the Government of Victoria in 2004 and our leases were extended until April 2006.

In the fourth quarter of 2004, in accordance with common government leasing practices, we relinquished approximately 382,000 gross acres to the Government of Victoria. During the first and second quarters of 2005, we drilled the first two dedicated CBM test wells on our EL 4416 license in the Gippsland Basin, located in Victoria, Australia. Gastar holds a 75% working interest in the CBM and Mineral Sands rights on the 1.4 million gross acre concession with the balance owned and operated by a subsidiary of Geostar. The wells are anticipated to be completed during the third quarter utilizing open-hole completion techniques commonly used in the Powder River Basin area.

While coalbed methane has been the primary focus of our efforts on the Gippsland property, our exploration license is not limited to CBM only. The Gippsland exploration licenses also include mineral rights on the properties. Our partner and we are conducting an advanced technical assessment of the mineral potential of these properties. While the assessment of the various minerals potential is in its early stages, the initial focus is on mineral sands, a major natural resource in other basins within Victoria. We have designed a mineral sands ground magnetic exploration program to further evaluate mineral sands potential. The coring portion of this program was recently completed and the data acquired is currently being evaluated.

Our exploration license requires that our net cumulative expenditure to date be approximately $1.5 million. Actual capital expenditures to date have totaled approximately $2.0 million, with an approximate $375,000 remaining to be spent over the balance of the term of the license. The license will expire April 2006, unless it is extended by the Government of Victoria. We anticipate that the Government of Victoria will require us to surrender approximately 35% of our current acreage upon license renewal for an additional five years.

Index to Financial Statements

Cherokee Basin, Kansas

We were a party to a purchase and sale contract to develop, as project operator, approximately 110,000 acre CBM property in the Cherokee Basin of Kansas. We conducted extensive geological, engineering, and economic evaluation of the property. The property was subsequently sold and, in addition to funds received in the divestment, we retained a small overriding royalty. The purchaser has been reported to have drilled numerous CBM wells, of which we have received overriding royalty interest assignments on approximately 116 wells.

Natural Gas and Oil Reserves

Our estimated total net proved reserves of natural gas and oil as of December 31, 2004, 2003 and 2002, and the present values of estimated future net revenues attributable to those reserves as of those dates, are presented in the following table. These estimates were prepared by Netherland, Sewell & Associates, Inc., independent reservoir engineers, and are part of their reserve reports on our natural gas and oil properties. Netherland, Sewell & Associates’s estimates were based on a review of geologic, economic, ownership and engineering data that we provided. In estimating the reserve quantities that are economically recoverable, Netherland, Sewell & Associates used end-of-period natural gas and oil prices. In accordance with U.S. Securities and Exchange Commission regulations, no price or cost escalation or reduction was considered. The PV(10) amounts shown in the table below are not intended to represent the current market value of the estimated natural gas and oil reserves.


	As of December 31,
	2004		2003		2002
Estimated Net Proved Reserves:
Net natural gas reserves (MMcf):
Proved developed		6,179		1,865		4,650
Proved undeveloped		15,221		5,999		10,526
Total		21,400		7,864		15,176

Net oil reserves (MBbl):
Proved developed		6		4		26
Proved undeveloped		—		—		—
Total		6		4		26

Total Proved Natural Gas and Oil Reserves:
(MMcfe)		21,436		7,887		15,330

PV(10) (in thousands) (1):
Proved developed	$	16,807	$	3,332	$	5,366
Proved undeveloped		8,802		4,805		5,250
Total	$	25,609	$	8,137	$	10,616

(1)	PV(10) represents the present value of estimated future net proved reserves before income taxes, using constant prices, discounted at 10% per annum. The prices used are presented below under the heading “Pricing Assumptions”.

As discussed above, in accordance with Securities and Exchange Commission regulations, estimates of our proved reserves and future net revenues are made using sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties, except to the extent a contract specifically provides for escalation. Estimated quantities of proved reserves and future net revenues therefrom are affected by natural gas and oil prices, which have fluctuated significantly in recent years. There are numerous uncertainties inherent in estimating natural gas and oil reserves and their estimated values, including many factors beyond our control. The reserve data set forth in this prospectus represent only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be

Index to Financial Statements

measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. Estimates with respect to proved reserves that may be developed and produced in the future often are based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing natural gas and oil prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates often are different from the quantities of natural gas and oil that ultimately are recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. Our estimated proved reserves have not been filed with or included in reports to any U.S. federal agency.

Pricing Assumptions

SEC regulations require that the gas and oil prices used in Netherland, Sewell & Associates’ reserve reports are the period-end prices for gas and oil at December 31, 2004, 2003 and 2002, respectively. These prices are projected without inflation for the life of the wells included in the reserve reports. The pricing assumptions are listed below:


	2004 Report Gas ($/MMBtu)		2003 Report Gas ($/MMBtu)		2002 Report Gas ($/MMBtu)
Powder River Basin (Wyoming and Montana)	$	5.52	$	5.58	$	3.12
Hilltop Area (East Texas)	$	5.82	$	5.97	$	4.74
Appalachian Basin (West Virginia)	$	6.45	$	5.71	$	4.80
Cherokee Basin (Kansas)	$	6.18	$	5.97	$	4.74
	Oil ($/Bbl)		Oil ($/Bbl)		Oil ($/Bbl)
Appalachian Basin (West Virginia)	$	39.75	$	29.25	$	27.50

Drilling Activities

The following indicates the number of natural gas and oil wells drilled during the periods indicated. As used below, “undecided” wells are wells for which permanent equipment was installed for the production of natural gas or oil but that as of each respective period end were in the process of de-watering.


	Number of Natural Gas Wells
	Productive		Dry		Undecided		Total Wells
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Six Months Ended June 30, 2005
Exploratory	1	0.7	—	—	5	3.5	6	4.2
Development	51	9.5	—	—	14	3.2	65	12.7

Year Ended December 31, 2004
Exploratory	2	1.3	—	—	3	1.5	5	2.8
Development	113	25.7	—	—	5	1.1	118	26.8

Year Ended December 31, 2003
Exploratory	1	0.8	—	—	—	—	1	0.8
Development	133	24.6	—	—	6	1.0	139	25.6

Year Ended December 31, 2002
Exploratory	—	—	—	—	1	0.1	1	0.1
Development	23	12.0	—	—	—	—	23	12.0

Index to Financial Statements

Acreage and Productive Wells

The following table sets forth our ownership interest in undeveloped acreage, developed acreage and productive wells in the areas indicated where we own a working interest as of June 30, 2005. Gross represents the total number of acres or wells in which we own a working interest. Net represents our proportionate working interest resulting from our ownership in gross acres or wells. Productive wells are wells in which we have a working interest and that are capable of producing natural gas or oil. Wells that are completed in more than one producing horizon are counted as one well.


	Undeveloped Acres		Developed Acres		Productive Wells
Region	Gross	Net	Gross	Net	Gross	Net
Powder River Basin, Wy.	35,605	12,613	21,160	9,256	282	160.4
Appalachia, W.Va.	25,466	12,532	1,187	735	9	6.6
California	3,040	3,040	—	—	—	—
Texas	51,206	32,240	1,920	1,760	3	2.9

Total United States	115,317	60,425	24,267	11,751	294	169.9

PEL 238	~1,997,800	~998,900	~2,200	~1,100	—	—
Gippsland Basin	~1,400,000	~1,050,000	—	—	—	—

Total Australia	~3,397,800	~2,048,900	~2,200	~1,100	—	—

The following table sets forth as of June 30, 2005, the expiration periods of the gross and net undeveloped acreage:


	Undeveloped Acres
	United States		Australia
	Gross	Net	Gross	Net
Nine Months Ended:
December 31, 2005	5.115	3,026	—		—

Twelve Months Ended:
December 31, 2006	30,164	11,665	~1,400,000	$	1,050,000
December 31, 2007	30,686	17,659	~1,997,800		998,900
December 31, 2008	20,081	11,692	—		—
December 31, 2009	6,831	3,416	—		—
December 31, 2010 and later	1,277	1,445	—		—

Index to Financial Statements

Volumes, Prices and Production Costs

The following table sets forth information with respect to our production volumes, average prices received and average production costs for the periods indicated:


	For the Three Months Ended March 31,				For the Years Ended December 31,
	2005		2004		2004		2003		2002
Production:
Natural gas (MMcf)		849.0		83.3		1,108.0		385.0		393.2
Oil (MBbld)		0.7		0.0		1.8		1.0		3.1
Oil Natural gas equivalents (Mmcfed)		853.2		83.4		1,118.8		391.0		411.6

Natural gas (MMcfd)		9.4		0.9		3.0		1.1		1.1
Oil (MBbl)		0.0		0.0		0.0		0.0		0.0
Oil Natural gas equivalents (Mmcfe)		9.5		0.9		3.1		1.1		1.1

Average Sales Prices:
Natural gas ($ per Mcf)	$	5.53	$	3.47	$	5.40	$	3.72	$	1.33
Oil ($ per Bbl)	$	48.80	$	31.13	$	40.08	$	27.89	$	20.15

Average costs ($ per Mcfe)	$	1.54	$	2.44	$	1.78	$	1.82	$	1.75

Markets and Customers

The success of our operations is dependent upon prevailing prices for natural gas and oil. The markets for natural gas and oil have historically been volatile and may continue to be volatile in the future. Natural gas and oil prices are beyond our control. However, rising demand for natural gas to fuel power generation and meet increasing environmental requirements has led some industry observers to indicate that long term demand for natural gas is increasing.

Our current United States production has access to major intrastate and interstate pipeline systems. We contract to sell gas from our properties with spot-market based contracts that vary with market forces on a monthly basis. While overall gas prices at major markets, such as Henry Hub in Louisiana, may have some impact on regional prices, the regional natural gas price at our production facilities may move somewhat independently of broad industry price trends. Because some of our operations are located in specific regions, we are directly impacted by regional natural gas prices in those regions regardless of pricing at major market hubs.

The East Texas Basin area has an extensive natural gas pipeline infrastructure in place. Our Deep Bossier production is transported to the Katy Hub in Katy, Texas, where numerous parties are available to purchase our natural gas production. Powder River Basin natural gas is sold under spot market contracts to major pipeline and natural gas marketing companies. These companies purchase essentially all of our current production.

The initial gas market for PEL 238 natural gas is anticipated to be a natural-gas fired electricity generation facility owned and operated by one of our joint venture partners and located near the town of Narrabri, New South Wales, Australia. Although there currently is no existing pipeline from the existing and planned CBM project areas, we and our joint venture partners are finalizing plans for a gathering system and pipeline to transport the CBM gas that we produce to the electricity generation facility. The longer term gas market for PEL 238 natural gas is considered to be future gas-fired power generation facilities in New South Wales and the industrial and residential markets in the Sydney and Newcastle areas of New South Wales. While there are currently no pipelines connecting our project areas within PEL 238 to the Sydney and Newcastle gas markets, a new 180 mile pipeline that will terminate within approximately 75 miles of our PEL 238 project areas has been announced and is expected to be begin construction in August 2005 and be operational by the second quarter of

Index to Financial Statements

2006. Our Gippsland Basin property has access to natural gas markets through three natural gas pipelines that cross our property and provide access to markets in Sydney, Melbourne and Tasmania.

Our very limited oil production in West Virginia is sold under spot sales transactions at market prices. The availability and price responsiveness of the multiple oil purchasers provides for a highly competitive and liquid market for oil sales.

We have not pre-sold any natural gas or oil and have no future volume delivery commitments of any kind.

During 2004, ETC Texas Pipeline Ltd. and Western Gas Resources, Inc. accounted for 59% and 10%, respectively, of the Company’s oil and natural gas revenues. During 2003, Western Gas Resources, Inc. and Equitable Gas Company, a division of Equitable Resources, Inc. accounted for 72% and 17%, respectively, of the Company’s oil and natural gas revenues. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

Competition

The natural gas and oil industry is intensely competitive and speculative in all of its phases. We encounter competition from other natural gas and oil companies in all areas of our operations. In seeking suitable natural gas and oil properties for acquisition, we compete with other companies operating in our areas of interest, including large natural gas and oil companies and other independent operators, which have greater financial resources and in many instances, have been engaged in the exploration and production business for a much longer time than we have. Many of our competitors also have substantially larger operating staffs than we do. Many of these competitors not only explore for and produce natural gas and oil but also market natural gas and oil and other products on a regional, national or worldwide basis. These competitors may be able to pay more for productive natural gas and oil properties and exploratory prospects and define, evaluate, bid for and purchase a greater number of properties and prospects than us. In addition, these competitors may have a greater ability to continue exploration activities during periods of low market prices. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

The prices of our natural gas and oil production are controlled by market forces. However, competition in the natural gas and oil exploration industry also exists in the form of competition to acquire leases and obtain favorable transportation prices. We are relatively small and may have difficulty acquiring additional acreage and/or projects and may have difficulty arranging for the transportation of our production. We also face competition in obtaining natural gas and oil drilling rigs and in sourcing the manpower to run them and provide related services.

Governmental Regulation

In addition to the environmental regulations discussed below under the heading “Environmental Regulation”, our natural gas and oil exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local governmental agencies. These laws and regulations, all of which are subject to change from time to time, include matters relating to land tenure; drilling and production practices such as discharge permits and the spacing of wells; the disposal of water resulting from operations and the processing, handling and disposal of hazardous materials such as hydrocarbons and naturally occurring radioactive materials; bonding requirements; reporting requirements; marketing and pricing policies; royalties; taxation; and foreign trade and investment.

Failure to comply with these rules and regulations can result in substantial penalties. Furthermore, we could be liable for personal injuries, property damage, spills, discharge of hazardous materials, reclamation costs, remediation, clean-up costs and other environmental damages as a consequence of acquiring a natural gas or oil opportunity.

Index to Financial Statements

The regulatory burden on the natural gas and oil industry increases our cost of doing business and affects our financial condition. Although we believe we are in substantial compliance with all applicable laws and regulations, we are unable to predict the future cost or impact of complying with such laws because those laws and regulations are frequently amended or reinterpreted. We are unable to predict what additional legislation or amendments may be proposed that will affect our operations or when any such proposals, if enacted, might become effective.

U.S. Regulation

Transportation and Sale of Natural Gas. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the regulations promulgated thereunder by the Federal Energy Regulatory Commission (FERC). In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of natural gas sales by producers began with the enactment of the Natural Gas Policy Act of 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining Natural Gas Act of 1938 and Natural Gas Policy Act of 1978 price and non-price controls affecting producer sales of natural gas effective January 1, 1993. Congress could, however, re-enact price controls in the future.

FERC regulates interstate natural gas pipeline transportation rates and service conditions, which affect the marketing of gas produced by us and the revenues received by us for sales of such natural gas. The FERC requires interstate pipelines to provide open-access transportation on a non-discriminatory basis for all natural gas shippers. The FERC frequently reviews and modifies its regulations regarding the transportation of natural gas with the stated goal of fostering competition within all phases of the natural gas industry. In addition, with respect to production onshore or in state waters, the intra-state transportation of natural gas would be subject to state regulatory jurisdiction as well.

Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective or their effect, if any, on our operations. The natural gas industry historically has been closely regulated; thus, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue indefinitely into the future. We do not believe that we will be affected by any action taken in a materially different way than other natural gas producers, gatherers and marketers with which we compete.

Federal Regulation of Sales and Transportation of Crude Oil. Our sales of crude oil and condensate are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. Certain regulations implemented by the FERC in recent years could result in an increase in the cost of pipeline transportation service. We do not believe, however, that these regulations affect us any differently than other producers.

Our operations are subject to extensive and continually changing regulation affecting the oil and natural gas industry. Many departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding on the oil and natural gas industry and its individual participants. The failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. We do not believe that we are affected in a significantly different manner by these regulations than are our competitors.

Regulation of Production. The production of oil and natural gas is subject to regulation under a wide range of state and federal statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds, and reports concerning operations. Most states in which we own

Index to Financial Statements

and operate properties, have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells, the spacing of wells, and the plugging and abandonment of wells and removal of related production equipment. Many states also restrict production to the market demand for oil and natural gas and several states have indicated interests in revising applicable regulations. These regulations can limit the amount of oil and natural gas we can produce from our wells, limit the number of wells, or limit the locations at which we can conduct drilling operations. Moreover, each state generally imposes a production or severance tax with respect to production and sale of natural gas, natural gas liquids and crude oil within its jurisdiction.

Australian Regulation

Commonwealth of Australia Laws and Regulations. The regulation of the natural gas and oil industry in Australia is similar to that of the United States, in that regulatory controls are imposed at both the state and commonwealth (federal) levels. Specific commonwealth regulations impose environmental, cultural heritage and native title restrictions on accessing resources in Australia. These regulations are in addition to any state level regulations. Foreign investment in Australia is regulated by the commonwealth through its foreign investment legislation and policy. In some circumstances, Australian foreign investment regulation and policy requires foreign interests to obtain prior approval from the Australian Government before investing in specific industry sectors. The Foreign Investment Review Board administers the regulation of foreign investment on behalf of the commonwealth. Its functions include analyzing proposals by foreign interests for investment in Australia and making recommendations to the Government on the compatibility of those proposals with Government policy and the relevant legislation. In some circumstances the acquisition of or formation of a new business will require review and approval under the commonwealth foreign investment policy and regulations. Australian law recognizes that in some instances native title, that is the laws and customs of the Aboriginal inhabitants, has survived European settlement. Native title will only survive if it has not been extinguished. Native title may be extinguished by an Act of Government, such as the creation of a title that is inconsistent with native title. This may include a grant of the right to exclusive possession through freehold title or lease. Native title may also be extinguished if the connection between the land and the group of Aboriginal people claiming native title has been lost. Native title legislation was enacted in 1993 in order to provide a statutory framework for deciding questions such as where native title exists, who holds native title and the nature of native title which were left unanswered by a 1992 Australian High Court decision. Native title claims by aboriginal groups’ can include claims over existing and potential natural gas and oil exploration and development areas. The commonwealth government has passed amendments to this legislation to clarify uncertainty in relation to the evolving native title legal regime in Australia created by the decision in another High Court case decided in 1996. Since 1998 the native title legislation has provided for interested parties to negotiate and register indigenous land use agreements with registered native title claimants in the early stages of development. Our Australian operations could be affected by native title claims by Aboriginal groups. Each authority to prospect, lease and pipeline license must be examined individually in order to determine validity and native title claim vulnerability.

Australia Gas Markets. Several statutory mechanisms regulate access rights to a range of infrastructure in Australia including gas transmission pipelines. These involve generic access regulations contained in the Trade Practices Act 1974 Cth. and industry specific schemes contained in specific legislative instruments, industry codes and schemes. Objectives of this regulatory regime include providing a process for establishing third party access to natural gas pipelines, facilitating the development and operation of a national natural gas market, promoting a competitive market for natural gas in which customers are able to choose their supplier, and providing a right of access to transmission and distribution networks on fair and reasonable terms and conditions. We cannot currently ascertain the impact of the regime objectives but believe it should benefit us.

Environmental Regulation

Our natural gas and oil exploration and production operations and similar operations that we do not operate but in which we own a working interest in the United States are subject to significant federal, state and local environmental laws and regulations governing environmental protection as well as the discharge of substances

Index to Financial Statements

into the environment. These laws and regulations may restrict the types, quantities and concentrations of various substances that can be released into the environment as a result of natural gas and oil drilling, production and processing activities; suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands and other protected areas; require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells; and restrict injection of liquids into subsurface strata that may contaminate groundwater. Governmental authorities have the power to enforce compliance with their laws, regulations and permits, and violations are subject to injunction, as well as administrative, civil and even criminal penalties. The effects of these laws and regulations, as well as other laws or regulations that are adopted in the future, could have a material adverse impact on our operations and other operations in which we own an interest. As discussed below, our Australian operations are similarly subject to regulation by Australian authorities.

We believe that we are in substantial compliance with existing applicable environmental laws and regulations. However, it is possible that new environmental laws or regulations or the modification of existing laws or regulations could have a material adverse effect on our operations and other operations in which we own an interest. As a general matter, the recent trend in environmental legislation and regulation is toward stricter standards, and this trend will likely continue. To date, we have not been required to expend extraordinary resources in order to satisfy existing applicable environmental laws and regulations. However, costs to comply with existing and any new environmental laws and regulations could become material. In addition, if substantial liabilities to third parties or governmental entities are incurred, the payment of such claims may reduce or eliminate the funds available for project investment or result in loss of our properties. Moreover, a serious incident of pollution may result in the suspension or cessation of operations in the affected area. Although we maintain insurance coverage against costs of clean-up operations, no assurance can be given that we are fully insured against all such potential risks. The imposition of any of these liabilities or compliance obligations on us may have a material adverse effect on our financial condition and results of operations.

The following is a summary of some of the existing environmental laws, rules and regulations to which our business operations are subject.

U.S. Environmental Laws

In the United States, environmental laws are implemented principally by the United States Environmental Protection Agency, or EPA, the Department of Transportation and the Department of the Interior, as well as other comparable state agencies.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes strict, joint and several liability without regard to fault or legality of conduct, on persons who are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance released at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring land owners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Although CERCLA currently excludes “petroleum” and “natural gas, natural gas liquids, liquefied natural gas or synthetic gas useable for fuel,” from the definition of “hazardous substance,” our operations as well as other operations in which we own an interest may generate materials that are subject to regulation as hazardous substances under CERCLA.

CERCLA may require payment for cleanup of certain abandoned waste disposal sites, even if such waste disposal activities were undertaken in compliance with regulations applicable at the time of disposal. Under CERCLA, one party may, under certain circumstances, be required to bear more than its proportional share of

Index to Financial Statements

cleanup costs if payment cannot be obtained from other responsible parties. CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. The scope of financial liability under these laws involves inherent uncertainties.

Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act, or RCRA, and comparable state programs regulate the management, treatment, storage and disposal of hazardous and non-hazardous solid wastes. Our operations and other operations in which we own an interest generate wastes, including hazardous wastes, that are subject to RCRA and comparable state laws. We believe that these operations are currently complying in all material respects with applicable RCRA requirements. Although RCRA currently exempts certain natural gas and oil exploration and production wastes from the definition of hazardous waste, we cannot assure you that this exemption will be preserved in the future, which could have a significant impact on us as well as of the oil and gas industry, in general.

We currently own, lease, own a working interest in, or operate numerous properties that for many years have been used by third parties for the exploration and production of natural gas and oil. Although we abide by standard industry operating and disposal practices, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us or in which we own an interest, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, many of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes (including substances disposed of or released by prior owners or operators), remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges. Our operations and other operations in which we own a working interest are subject to the Clean Water Act, or CWA, as well as the Oil Pollution Act, or OPA, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States, including wetlands. Under the CWA and OPA, any unpermitted release of pollutants from operations could cause us to become subject to: the costs of remediating a release; administrative, civil or criminal fines or penalties; or OPA specified damages, such as damages for loss of use and natural resource damages. In addition, in the event that spills or releases of produced water from natural gas and oil production operations were to occur, we would be subject to spill notification and response requirements under the CWA or the equivalent state regulatory program. Depending on the nature and location of these operations, spill response plans may also have to be prepared.

Our natural gas and oil exploration and production operations and other operations in which we own an interest generate produced water as a waste material, which is subject to the disposal requirements of the CWA, Safe Drinking Water Act, or SDWA, or an equivalent state regulatory program. Naturally occurring groundwater is also typically produced by CBM production in our operations or in other operations in which we own an interest. This produced water is disposed of by re-injection into the subsurface through disposal wells, discharge to the surface, or in evaporation ponds. Whichever disposal method is used, produced water must be disposed of in compliance with permits issued by regulatory agencies, and in compliance with applicable environmental regulations. This water can sometimes be disposed of by discharging it under discharge permits issued pursuant to the CWA or an equivalent state program. Another common method of produced water disposal is subsurface injection in disposal wells. Such disposal wells are permitted under the SDWA, or an equivalent state regulatory program. To date, we believe that all necessary surface discharge or disposal well permits have been obtained and that the produced water has been discharged into the produced water disposal wells in substantial compliance with such obtained permits and applicable laws.

Index to Financial Statements

Air Emissions. The Clean Air Act, or CAA, and comparable state laws and regulations govern emissions of various air pollutants through the issuance of permits and the imposition of other requirements. Air emissions from some equipment found at our operations or other operations in which we own an interest, such as gas compressors, are potentially subject to regulations under the Clean Air Act or equivalent state and local regulatory programs, although many small air emission sources are expressly exempt from such regulations. To the extent that these air emissions are regulated, they are generally regulated by permits issued by state regulatory agencies. To date, we believe that no unusual difficulties have been encountered in obtaining air permits. However, in the future, we may be required to incur capital expenditures in connection with maintaining or obtaining operating permits and approvals addressing air emission-related issues.

CBM production operations involve the use of gas-fired compressors to transport gas that is produced. Emissions of combustible by-products from compressors at one location may be great enough to subject the compressors to CAA and comparable state air quality regulation requirements for pre-construction and operating permits. To date, we believe that such gas-fired compressors operated by us or at other operations in which we own a working interest have been operated in substantial compliance with obtained permits and the applicable federal, state and local laws and regulations without undue cost to or burden on our business activities. Another air emission associated with these CBM operations that may be subject to regulation and permitting requirements is particulate matter resulting from construction activities and vehicle traffic. To date, we do not believe there has been any unusual difficulty in complying with requirements related to particulate matter.

Other Laws and Regulations. Our operations and other operations in which we own a working interest are also impacted by regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials. Furthermore, owners, lessees and operators of natural gas and oil properties are also subject to increasing civil liability brought by surface owners and adjoining property owners. Such claims are predicated on the damage to or contamination of land resources occasioned by drilling and production operations and the products derived therefrom, and are often based on negligence, trespass, nuisance, strict liability or fraud.

In addition, our operations and other operations in which we own an interest may in the future be subject to the regulation of greenhouse gas emissions. In 1997, numerous countries reached agreement on the Kyoto Protocol to the United Nations Framework Convention on Climate Change. If the Protocol enters into force, adopting countries would be required to implement national programs to reduce emissions of certain gases, generally referred to as greenhouse gases, that are suspected of contributed to global warming. The Bush Administration has indicated it will not support ratification of the Protocol, and Congress has resisted recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from certain greenhouse gas emission sources, primarily power plants. The oil and gas exploration and production industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations and other operations in which we own an interest currently are not adversely impacted by current state and local climate change initiatives; however, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

Finally, legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and gas facilities. Our operations and the operations of the oil and gas industry in general may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Australian Environmental Laws

Australia has environmental laws and regulations that are similar in scope and impact to United States environmental laws and regulations. Similar approval, licensing and operational impacts apply at a

Index to Financial Statements

commonwealth, state and local government level. As a result, environmental laws and regulations can result in similar licensing and operational impacts in Australia that are similar to those discussed above with respect to the United States.

The legislation regulating environmental assessment at a commonwealth level is the Environmental Protection and Biodiversity Conservation Act 1999 (Cth.). This Commonwealth Act establishes a regime for protecting the environment, flora and fauna biodiversity and Australian national heritage. It requires any person taking an action which could have a significant impact on one of these values to refer it to the commonwealth Minister for the Environment for consideration and potential assessment. The Act only applies to matters of national environmental or heritage significance. These are matters which impact on a world heritage site, Ramsar wetlands, species which are listed as threatened under the Act, migratory species, nuclear actions and commonwealth marine areas or places listed on the commonwealth heritage list. Operators are required to assess their projects to determine whether an action is likely to have a significant impact on matters of national environmental significance, and make a decision respecting submission of that assessment to a public referral process. The referral is expected to add some time to the existing approval process but have little impact on most routine activities and operations. In addition, see the discussion in “Business—Gunnedah Basin, New South Wales, Australia” for a discussion of the New South Wales government’s bioregion study involving PEL 238. Environmental protection is also regulated in each state and territory by specific legislation enacted by each state or territory. The governments of New South Wales and Victoria both have a suite of legislation regulating environmental matters in their states. The legislation imposes a licensing approval and contamination management scheme which may impact on our operations and impose a liability which may extend beyond the time period during which properties are operated, occupied or owned. The laws and regulations also restrict emissions to air, land and water and may control or regulate substances which can be released into the environment and the manner in which they are transported and disposed of. Environmental laws and regulations protecting archeological relics, natural and built heritage as well as native flora and fauna can also impact on our operations and impose obligations in respect of restitution or replacements well as liability in respect of damage.

Australia Gas Markets. Several statutory mechanisms regulate access rights to a range of infrastructure in Australia including gas transmission pipelines. These involve generic access regulations contained in the Trade Practices Act 1974 Cth. and industry specific schemes contained in specific legislative instruments, industry codes and schemes. Among the objectives of this regulatory regime are: to provide a process for establishing third party access to natural gas pipelines, to facilitate the development and operation of a national natural gas market, to promote a competitive market for natural gas in which customers are able to choose their supplier, and to provide a right of access to transmission and distribution networks on fair and reasonable terms and conditions. We cannot currently ascertain the impact of the regime objectives but believe it should benefit us.

Legal Proceedings

First Sourcenergy Group, Inc., one of our wholly owned subsidiaries, is a named party to an Arbitration proceeding captioned Estate of Virgil Sparks and Oil Wells of Kentucky, Inc. v First Sourcenergy Group, Inc. and Geostar. The dispute involves historical dealings with the development of an Authority to Prospect (“ATP”) Area in Queensland, Australia, as well as an ancillary Agreement. The formal Arbitration is in discovery stages. First Sourcenergy Group, Inc. and Geostar have moved to dismiss the Arbitration on the grounds of a claimed prior settlement and release agreement. First Sourcenergy Group, Inc. and Geostar are vigorously defending the Arbitration, and firmly believe that its position is sound. Further, an interest in ATP 560 was transferred from First Sourcenergy Group, Inc. to Conquest Exploration, Inc. in 2001, the result of which means that, although First Sourcenergy Group, Inc. is a named defendant, Conquest Exploration, Inc.) and Geostar would bear primary liability from this Arbitration action.

On May 3, 2005 Western Gas Resources, Lance Oil and Gas Company, Inc. and Williams Production RMT Company filed a lawsuit against us and others over a dispute that has arisen concerning a June 2002 Lease Exchange and Purchase Agreement between certain of the parties. The issue involves a certain gas gathering

Index to Financial Statements

agreement and its applicability to some of the properties exchanged under the June 2002 Agreement. A formal response to the Complaint was filed in June 2005. We believe that is has multiple strong defenses to this action and intends to vigorously advance its positions. Further, at the very preliminary stage, it would appear that our exposure is significantly lower that that of the other defendants

We are subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to contractual agreements and management decisions, result in the accrual of estimated future removal and site restoration costs. These costs are initially measured at a fair value and are recognized in the consolidated financial statements as the resent value of expected future cash flows. Subsequent to the initial measurement, the effect of the passage of time on the liability for the ARO (accretion expense) and the amortization of the ARO cost are recognized in the results of operations. Costs attributable to these commitments and contingencies are expected to be incurred over an extended period of time and are to be funded mainly from our cash provided by operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, it could be material for any one quarter or year.

In addition, we are involved in various other claims and legal actions arising out of the normal course of our business. We do not expect that the outcome of these proceedings will have a material adverse effect on our financial position, results of operations or cash flow.

Employees

Currently, we have nine employees, all of whom are full time. We use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. On those properties where we are not the operator, we rely on outside operators to drill, produce and market our natural gas and oil.

Index to Financial Statements

MANAGEMENT

Directors, Officers and Certain Named Individuals

Our directors, executive officers and certain named individuals and their ages as of August 1, 2005 are as follows:


Name	Age	Position
Thomas E. Robinson.	50	Chairman of the Board of Directors
J. Russell Porter.	43	Chief Executive Officer, President, Chief Operating Officer and Director
Michael A. Gerlich	51	Chief Financial Officer & Vice President
Frederick J. Lambert	35	Controller
Sara-Lane Sirey	37	Corporate Secretary
Abby Badwi	58	Director
Thomas Crow	73	Director
Matthew J. P. Heysel.	48	Director
Richard Kapuscinski	43	Director

Thomas E. Robinson has been a member and the Chairman of our Board of Directors since February 2001. Mr. Robinson has more than 20 years of experience investing in various areas in the natural gas and oil industry, both as an investor in and developer of exploration projects. During this period, he directed natural gas and oil drilling and production activities for Geostar and individually in the United States (including the states of Michigan, Illinois, Texas, Kansas, Kentucky and Wyoming) and New South Wales, Victoria and the Cooper Basin in Australia. Mr. Robinson is the Chief Executive Officer of Geostar, a position he has held since January 1994. From May 2000 to February 2004, Mr. Robinson also served as our President and Chief Executive Officer.

J. Russell Porter has been a member of our Board of Directors and has served as our Chief Executive Officer and President since February 2004. From September 2000 to February 2004, he served as our Chief Operating Officer. Mr. Porter has a unique background, with approximately 14 years of natural gas and oil exploration and production experience and five years of banking and investment experience specializing in the natural gas and oil industry. From April 1994 to September 2000, Mr. Porter served as an Executive Vice President of Forcenergy, Inc., a publicly traded exploration and production company, where he was responsible for the acquisition and financing of the majority of its assets across the United States and Australia. Mr. Porter holds a BS degree in Petroleum Land Management from Louisiana State University and a MBA from the Kenan-Flagler School of Business at the University of North Carolina at Chapel Hill.

Michael A. Gerlich joined Gastar in May 2005 as Vice President and Chief Financial Officer. Prior to joining Gastar Mr. Gerlich was Senior Vice President – Accounting and Finance for Calpine Natural Gas L.P., formerly known as Sheridan Energy, Inc. He joined Sheridan Energy in July 1994 as Vice President and Chief Financial Officer. Over a 10 year period prior to joining Sheridan Energy, Mr. Gerlich held various accounting and finance positions with Trinity Resources, Ltd., with his last position being Executive Vice President and Chief Financial Officer. Mr. Gerlich was also with a big four accounting firm, where the focus of his practice was with energy related clients. Mr. Gerlich is a Certified Public Accountant and graduated with honors from Texas A&M University with a degree in accounting.

Frederick J. Lambert has been our Controller since May 2000. He additionally is the Controller of Geostar Corporation, a position he has held since February 1997. Previously, Mr. Lambert worked as a staff accountant for Shoemaker & Wilson, P.C., where the focus of the practice was oil and gas exploration and taxation. He is a graduate of Central Michigan University with a degree in Accounting and is a Certified Public Accountant.

Sara-Lane Sirey, LLB is an independent contractor who has served as the Corporate Secretary of Gastar and General Corporate Canadian Counsel since May 2000. From July 1993 to April 2001, she served as an attorney at the law firm of Armstrong Perkins Hudson LLP (formerly Ogilvie and Company) in Calgary,

Index to Financial Statements

Alberta, Canada, becoming a partner in 1999. Focusing on corporate/securities law, she has acted for issuers, in all industry segments, in Canada, the United States and internationally, focusing on corporate reorganizations, commercial transactions and initial public offerings of junior emerging companies as well as equity and debt financings, mergers and acquisitions and commercial transactions of senior established companies. Ms. Sirey obtained her Bachelor of Laws degree at the University of Saskatchewan in 1992.

Abby F. Badwi has been a member of our Board of Directors since February 2004. Mr. Badwi is an international energy executive with more than 30 years experience in the exploration, development and production of oil and gas fields in North America, South America, Asia and the Middle East. He is currently (and has been since July 2005) the President and CEO of Rally Energy, an oil and gas company with operations in Egypt, Pakistan and Canada. Since 2003, Mr. Badwi has also held the position of President of Corrundum Energy Ltd., a private company providing advisory services and investments in oil and gas ventures. From 2000 to 2002 he has served as President and CEO of Geodyne Energy Inc., an oil and gas exploration and production company. From 1994 to December 1999, Mr. Badwi served as President and Chief Operating Officer of Carmanah Resources Ltd., a Calgary, Alberta-based company with oil holdings in Canada, Indonesia and Venezuela. He has been an officer and director of several Canadian public and private companies and is currently a director of Arpetrol Inc., Gastar Exploration Ltd, Sustainable Energy Technologies Ltd., and Fairmount Energy Inc. Mr. Badwi is a geology graduate of the University of Alexandria, Egypt.

Thomas L. Crow has been a director since April 2002. Mr. Crow was the founder and President of Cobra Golf Inc. (a worldwide leading manufacturer of golf clubs which was listed on NASDAQ) from 1973 to 1994 and served as Vice President from 1994 to 1996 when Cobra Golf Inc. was acquired to be a subsidiary of Fortune Brand Inc. (a significant NYSE conglomerate). From 1997 to 2002, Mr. Crow remained as Chairman Emeritus of Cobra Golf Inc. Mr. Crow is currently an independent businessman.

Matthew J. P. Heysel joined our Board of Directors in January 2002. From 2000 until his resignation in May, 2005, Mr. Heysel served as Chairman of the Board of Directors and Chief Executive Officer of Big Sky Energy Corporation, an international oil and gas company. Mr. Heysel was also Chairman of Big Sky Energy Corporation’s subsidiaries, Big Sky Energy Kazakhstan Ltd. and Big Sky Energy Atyrau Ltd. He also serves as the Chairman of both Big Sky Network Canada Ltd., a Canadian company located in Chengdu, China, to provide high speed internet technology services, and Chengdu Big Sky Technology Services Ltd., a Canadian company located in Calgary, Alberta to provide high speed internet technology services. From 1997 to 1999, Mr. Heysel served as an investment banker at Yorkton Securities, a Canadian independent securities firm, where he was responsible for corporate finance in the oil and gas sector. From 1987 to 1997, Mr. Heysel was with Sproule Associates Limited, Canada’s largest petroleum engineering and geological consulting firm, holding the positions of Engineering Manager, Senior Associate, and Manager of International Projects. Mr. Heysel served as a Director of Canada’s Petroleum Society from 1989 to 1992 and also sits as a board member of public and private oil and gas companies active in North America. Mr. Heysel obtained an Honours Bachelor’s Science Degree from the University of Western Ontario in 1979, and a Bachelor of Science-Chemical Engineering from the University of Toronto in 1982 and has been a practicing professional Petroleum Engineer since that date.

Mr. Heysel obtained an Honours Bachelor’s Science Degree from the University of Western Ontario in 1979, and a Bachelor of Science—Chemical Engineering from the University of Toronto in 1982.

Richard Kapuscinski has been a member of our Board of Directors since July 2000. Mr. Kapuscinski is a Director of Marketing at Turbo Genset Inc, as the North American Business Development Manager since November 1999. Turbo Genset Inc. is a designer and manufacturer of innovative products for power generation and power conditioning. From 1986 to 1999, Mr. Kapuscinski worked as a Sales Marketing Manager with Tyco International (US) Inc. (formerly Keystone Valve), and from 1984 to 1986, he worked as an Engineering Technologist with Esso Petroleum. Mr. Kapuscinski is a Certified Mechanical Engineering Technologist and is a member of the Ontario Association of Certified Engineering Technicians and Technologists and the Instrument Society of America. He studied Mechanical Engineering at Lambton College in Sarnia, Ontario, Canada having a strong influence in the Petroleum and Petrochemical Industry.

Index to Financial Statements

Executive Compensation

Summary of Compensation

The following table shows all compensation awarded or paid to, or earned by, our executive officers and certain named individuals for the years ending December 31, 2004, 2003 and 2002. Except as reflected in the following table, none of our executive officers received compensation in excess of $100,000 in any of the fiscal years ending December 31, 2004, 2003 or 2002.

Summary Compensation Table


								Long term Compensation
Name and Principal Position	Year	Annual Compensation						Awards	Payouts	All Other Compensation
Name and Principal Position	Year	Salary		Bonus		Other Annual Compensation (1)		Securities Underlying Options	Long Term Incentive Plan Payments	All Other Compensation
Thomas E. Robinson, Chairman of the Board and Chief Executive Officer (2)(3)	2004 2003 2002	$	— — —	$	— — —	$	— — —	500,000 — —	— — —		— — —

J. Russell Porter, Chief Executive Officer (4)	2004 2003 2002	$ $ $	350,000 350,000 204,167	$	150,000 — —		— — —	1,000,000 — —	— — —		— — —

Victor Hughes, Former Chief Financial Officer (3)(5)	2004 2003 2002		— — —		— — —		— — —	200,000 — —	— — —		— — —

Frederick J. Lambert, Controller (3)(6)	2004 2003 2002	$	46,875 — —		— — —		— — —	150,000 — —	— — —		— — —

Sara-Lane Sirey, Corporate Secretary (7)	2004 2003 2002		— — —		— — —		— — —	50,000 — —	— — —	$ $ $	69,848 58,688 43,438

(1)

As permitted by the rules promulgated by the Securities and Exchange Commission, no amounts are shown with respect to perquisites and other personal benefits, securities or property for each individual named in the table above that did not exceed the lesser of $50,000 or 10% of the sum of the amounts in the annual salary and bonus columns reported for such individual.

(2)	Mr. Robinson resigned as Chief Executive Officer on February 17, 2004 but continues to hold the title of Chairman of the Board.

(3)	Mr. Robinson, Mr. Hughes and Mr. Lambert received no cash compensation from us for any services performed by them.

(4)

From September 2000 until February 17, 2004, Mr. Porter served as our Chief Operating Officer. Mr. Porter’s salary for 2002, 2003 and 2004 was paid by Geostar. On February 17, 2005, Mr. Porter was appointed our Chief Executive Officer. Mr. Porter’s bonus for 2004 was paid by Gastar in 2005. Under the terms of his current employment agreement, he receives an annual base salary of $450,000, plus bonus.

(5)	Mr. Hughes resigned in February 2005. Options granted to Mr. Hughes in 2004 were cancelled in May 2005 as a result of his resignation.

(6)	Mr. Lambert acted as Interim Chief Financial Officer from February 2005 until May 17, 2005, the date on which Mr. Gerlich joined us as Vice President and Chief Financial Officer.

(7)	Ms. Sirey, an independent contractor, acts as our Corporate Secretary. Cash amounts paid by us for her services are shown as Other Compensation.

Index to Financial Statements

For additional information on cost sharing arrangements with Geostar, see “Certain Relationships and Related Party Transactions”.

Michael A. Gerlich joined us on May 17, 2005 as Vice President and Chief Financial Officer. Under the terms of his employment contract, Mr. Gerlich receives an annual base salary of $275,000.

Stock Option Grants and Exercises

The following table shows certain information about stock option grants to our executive officers and certain named individuals during the year ended December 31, 2004.


Name	Number of Securities Underlying Options/ SARs Granted	Percentage of Total Options/ SARs Granted to Employees in 2004		Strike Price (CDN$)	Expiration Date	Potential Realizable Value at Assumed Annual Rates of Stock Appreciation for Option Term (CDN$)
Name	Number of Securities Underlying Options/ SARs Granted			Strike Price (CDN$)	Expiration Date	5%	10%
Thomas E. Robinson, Chairman of the Board and former Chief Executive Officer (1)	500,000	9.1	%	3.41	08/04/09	471,060	1,040,920
J. Russell Porter, Chief Executive Officer (2)	1,000,000	18.2	%	3.41	08/04/09	942,120	2,081,839
Victor Hughes, Former Chief Financial Officer(3)	200,000	3.6	%	3.41	08/04/09	188,424	416,368
Frederick J. Lambert, Controller	100,000	1.8	%	3.41	08/04/09	141,318	312,276
Sara-Lane Sirey, Corporate Secretary	50,000	0.9	%	3.41	08/04/09	47,106	104,092

(1)	Mr. Robinson resigned as Chief Executive Officer on February 17, 2004 but continued to hold the title of Chairman of the Board.

(2)	On February 17, 2004, Mr. Porter was appointed our Chief Executive Officer. From September 2000 until February 17, 2004, he served as Chief Operating Officer.

(3)	Mr. Hughes resigned in February 2005. Options granted to Mr. Hughes and unexercised were cancelled in May 2005 as a result of his resignation.

The following table shows information about stock options held as of December 31, 2004 by our officers and certain named individuals. None of our executive officers and certain named individuals exercised any stock options during 2004.


Name	Number of Securities Underlying Unexercised Options at December 31, 2004		Value of Unexercised in the Money Options at December 31, 2004 (1)
	Exercisable	Unexercisable	Exercisable		Unexercisable
Thomas E. Robinson, Chairman of the Board and former Chief Executive Officer (2)	1,442,400	980,800	CDN$	1,644,336	CDN$	793,112
J. Russell Porter, Chief Executive Officer (3)	650,000	750,000	CDN$	578,500	CDN$	367,500
Victor Hughes, Former Chief Financial Officer (4)	700,000	300,000	CDN$	1,782,000	CDN$	212,000
Frederick J. Lambert, Controller	300,000	250,000	CDN$	342,000	CDN$	187,500
Sara-Lane Sirey, Corporate Secretary	300,000	150,000	CDN$	342,000	CDN$	138,500

(1)	A per share price of CDN$3.90, the closing price on the Toronto Stock Exchange on December 31, 2004, was used for purposes of this calculation.

(2)	Mr. Robinson resigned as Chief Executive Officer on February 17, 2004 but continued to hold the title of Chairman of the Board.

Index to Financial Statements

(3)	On February 17, 2004, Mr. Porter was appointed our Chief Executive Officer. From September 2000 until February 17, 2004, he served as Chief Operating Officer.

(4)	Mr. Hughes resigned in February 2005. Options held by Mr. Hughes were cancelled in May 2005 as a result of his resignation.

On February 17, 2004, Mr. Porter was appointed our Chief Executive Officer. From September 2000 until February 17, 2004, he served as Chief Operating Officer.

Equity Compensation Plan Information

Our 2002 Stock Option Plan was approved and ratified by our shareholders on July 5, 2002. The 2002 Stock Option Plan superseded and replaced our prior stock-based compensation plans. Unexercised stock options granted under our prior stock option plans that had not expired or been cancelled on the effective date of the 2002 Stock Option Plan were ratified and confirmed as included under the 2002 Plan. Consequently, all currently outstanding stock options are subject to the terms of the 2002 Stock Option Plan.

The 2002 Stock Option Plan authorizes the issuance of options to purchase a maximum of 25 million common shares. If any option granted under the 2002 Stock Option Plan expires or terminates for any reason in accordance with the terms of the 2002 Stock Option Plan without being exercised, the unpurchased shares subject to that option will become available for other option grants under the 2002 Stock Option Plan. The 2002 Stock Option Plan is our only equity compensation plan.

As of August 1, 2005, we had granted options to purchase 17,329,600 common shares pursuant to the 2002 Stock Option Plan, 11,705,850 shares of which shares are vested but have not been exercised.

The 2002 Stock Option Plan is administered by our Board of Directors. Pursuant to the 2002 Stock Option Plan, our Board of Directors may allocate non-transferable options to purchase common shares to directors, officers, employees and consultants of Gastar and its subsidiaries. At the time of granting options under the 2002 Stock Option Plan, the aggregate number of common shares underlying all options granted under the 2002 Stock Option Plan and the aggregate number of common shares underlying the options granted to each individual under the 2002 Stock Option Plan may not exceed the maximum number permitted by any stock exchange on which our common shares are listed or by any other regulatory body having jurisdiction. Options issued pursuant to the 2002 Stock Option Plan have an exercise price determined by the Board of Directors, but that exercise price cannot be less than the price permitted by any stock exchange on which our common shares are then listed.

Stock Appreciation Rights, Restricted Shares and Long term Incentive Plans

We did not grant any stock appreciation rights or restricted shares to any of our executive officers or directors during the year ended December 31, 2004. No stock appreciation rights were exercised during the year ended December 31, 2004.

We do not have any long term incentive plans other than the 2002 Stock Option Plan.

Employment Agreements and Termination of Employment and Change of Control Arrangements

We have entered into an employment agreement with our Chief Executive Officer and Chief Financial Officer. Each employment agreement shall continue unless terminated in accordance with the provisions of his respective agreement. Each employment agreement provides for a base salary, a bonus, participation in our health plans and other fringe benefits. The agreements also include confidentiality provisions.

Mr. Porter’s 2005 annual base salary is $450,000, with an annual bonus not to be less than 20% of his annual salary. He received a bonus in 2004 of $150,000. Additionally, Mr. Porter will receive reimbursement for

Index to Financial Statements

club and organizational membership used in furtherance of the Company’s business. We will pay Mr. Porter severance benefits if his employment is terminated by death, disability, or if he or Gastar terminates his employment with proper notice. Severance benefits will be equal to two times his total compensation, as shown on his most recent Form W-2. Severance benefits will be payable over the “Severance Pay Period”, as set forth in his employment agreement. Mr. Porter will receive no severance payment if his termination is due to “Reasonable Cause”.

Mr. Gerlich’s base salary is $275,000. Annual bonuses are at the discretion of the Company’s board of directors. Upon becoming Chief Financial Officer, Mr. Gerlich was granted a stock option to acquire 250,000 shares of our common shares. Additionally, upon his employment’s one year anniversary, he will be granted an additional stock option to acquire 125,000 common shares. We will pay Mr. Gerlich severance benefits if his employment is terminated by any reason other than “Reasonable Cause”. Severance benefits will be equal to two times his most recent annual compensation (exclusive of bonuses received or other non-cash compensation) if notice is received after May 17, 2006. If notice is received prior to May 17, 2006, the severance amount equal to one times his most recent annual compensation (exclusive of bonuses received or other non-cash compensation). Severance benefits will be payable over the “Severance Pay Period”, as set forth in his employment agreement.

Compensation of Directors

Directors currently do not receive any cash or other compensation for their services as members of our Board of Directors, but they are reimbursed for certain expenses incurred in connection with attendance of Board and committee meetings in accordance with company policy.

Directors are eligible to receive stock option grants under our 2002 Stock Option Plan. During the fiscal year ended December 31, 2004, we did not grant any stock options to any of our directors under our 2002 Stock Option Plan.

Compensation Committee Interlocks and Insider Participation

From January 1, 2004 until May 28, 2004, the compensation committee of our Board of Directors, which we refer to as the Remuneration Committee, was comprised of Messrs. Crow, Kapuscinski, Heysel and Robinson. Other than Mr. Robinson who served as our Chief Executive Officer until February 17, 2004, no member of the Remuneration Committee was during the 2004 fiscal year or at any time prior to the 2004 fiscal year an officer or employee of us or any of our subsidiaries. As of May 28, 2004, our Remuneration Committee is comprised of Messrs. Badwi, Crow, Kapuscinski and Heysel, none of whom is or has ever served as an officer or employee of Gastar or any of its subsidiaries. None of our executive officers serves as a member of the board of directors or compensation committee (or committee performing similar functions) of any entity that has one or more executive officers who serve on our Board of Directors or Remuneration Committee.

Directors’ and Officers’ Liability Insurance

We carry directors’ and officers’ liability insurance with a policy limit of $20.0 million.

Index to Financial Statements

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information about the beneficial ownership of common shares as of August 1, 2005 by:

•

Each of our directors;

•

Our executive officers named in the Summary Compensation Table above;

•

All of our directors and executive officers as a group; and

•

Each person known to us to be the beneficial owner of more than 5% of our outstanding common shares.

For purposes of the following table, a person is deemed to be the beneficial owner of securities that can be acquired by that person within 60 days from August 1, 2005 upon the exercise of warrants or options or upon the conversion of convertible securities. Each beneficial owner’s percentage is determined by assuming that options, warrants or conversion rights that are held by that person regardless of price, but not those held by any other person, and which are exercisable within 60 days from August 1, 2005, have been exercised.

Unless otherwise indicated and subject to community property laws where applicable, we believe that all persons named in the following table have sole voting and investment power over all shares reported as beneficially owned by them. With the exception of Mr. Porter and Mr. Gerlich, the address for Geostar Corporation, Messrs. Ferguson, Lambert, Robinson, Badwi, Crow, Heysel and Kapuscinski and Ms. Sirey is 2480 W. Campus Drive, Building C, Mt. Pleasant, Michigan 48858. The address of Mr. Porter and Mr. Gerlich is 1331 Lamar Street, Suite 1080, Houston, Texas 77010.

The information in the following table is based upon information supplied by officers, directors, certain named individuals and principal shareholders. Applicable percentages are based on 128,811,436 common shares outstanding on August 1, 2005, subject to adjustment for each beneficial owner as described above.


Name of Beneficial Owner	Number of Common Shares Beneficially Owned	Percent of Class
Our 5% Owners:
Geostar Corporation	12,574,565	9.8	%
Tony Ferguson (1)	11,417,487	8.7	%
Our Officers, Directors and Certain Named Individuals:
J. Russell Porter, Chief Executive Officer (2)	2,930,000	2.3	%
Michael A. Gerlich, Vice President and Chief Financial Officer (3)	—	—
Sara-Lane Sirey, Corporate Secretary (4)	781,086	*
Frederick J. Lambert, Controller (5)	837,500	*
Thomas E. Robinson, Chairman of the Board (6)	14,966,499	11.4	%
Abby Badwi, Director (7)	75,000	*
Thomas Crow, Director (8)	512,500	*
Matt Heysel, Director (9)	253,078	*
Richard Kapuscinski, Director (10)	371,833	*
All officers, directors and certain named individuals as a group (9 persons)	20,727,496	15.6	%

*	Less than 1.0%.

(1)	Includes direct ownership of 6,960,000 common shares, 2,409,287 common shares beneficially owned through Geostar Corporation and stock options to purchase 2,048,200 common shares, all of which are vested or will vest within 60 days of August 1, 2005.

Index to Financial Statements

(2)

Includes direct ownership of 2,280,000 common shares and stock options to purchase 650,000 common shares, all of which are vested or will vest within 60 days of August 1, 2005. On February 17, 2004, Mr. Porter was appointed our Chief Executive Officer. From September 2000 until February 17, 2004, he served as Chief Operating Officer.

(3)	Mr. Gerlich was appointed our Vice President and Chief Financial Officer in May 2005.

(4)	Includes direct ownership of 368,586 common shares and stock options to purchase 412,500 common shares, all of which are vested or will vest within 60 days of August 1, 2005.

(5)	Includes direct ownership of 400,000 common shares and stock options to purchase 437,500 common shares, all of which are vested or will vest within 60 days of August 1, 2005.

(6)

Includes direct ownership of 9,774,658 common shares, 3,143,641 common shares beneficially owned through Geostar Corporation and stock options to purchase 2,048,200 common shares, all of which are vested or will vest within 60 days of August 1, 2005. Mr. Robinson resigned as Chief Executive Officer on February 17, 2004 but continued to hold the title of Chairman of the Board.

(7)	Includes stock options to purchase 75,000 common shares, all of which are vested or will vest within 60 days of August 1, 2005.

(8)	Includes direct ownership of 300,000 common shares and stock options to purchase 212,500 common shares, all of which are vested or will vest within 60 days of August 1, 2005.

(9)	Includes direct ownership of 78,078 common shares and stock options to purchase 175,000 common shares, all of which are vested or will vest within 60 days of August 1, 2005.

(10)	Includes direct ownership of 146,833 common shares and stock options to purchase 225,000 common shares, all of which are vested or will vest within 60 days of August 1, 2005.

Index to Financial Statements

DESCRIPTION OF CAPITAL STOCK

The following description of our capital stock does not purport to be complete and is subject to, and qualified in its entirety by, our articles of incorporation and bylaws, which are exhibits to the registration statement of which this prospectus forms a part.

Common Shares

We have an unlimited number of common shares authorized under our articles of incorporation. We have no other authorized classes of capital stock.

As of August 1, 2005, we had outstanding 128,811,436 common shares and we had reserved 29,176,203 shares for issuance upon exercise or conversion of outstanding options, warrants and convertible securities.

Common Share Purchase Warrants

As of August 1, 2005, we had warrants outstanding to acquire 4,997,288 shares of our common stock as follows:


Outstanding in Connection with:	Number of Warrants	Exercise Price	Date Granted	Expiration Date
$4.0 million private placement of working interests dated September 23, 2002	2,005,027	CDN $2.35	09/23/02	09/23/05
$3.25 million private placement of 10% unsecured subordinated notes	232,521	$2.76 - 3.03	04/20/04 - 07/12/04	04/20/09 - 07/12/09
$15.0 million private placement of 15% senior notes dated July 24, 2004	510,525	$3.23	10/13/04	10/13/07
$10.0 million private placement of 15% senior notes dated October 7, 2004	1,989,475	$3.63	10/13/04	10/13/07
$30.0 million private placement of 9.75% convertible senior unsecured debentures	259,740	CDN $4.65	11/15/04 and 11/16/04	05/12/06

Voting Rights

Holders of our common shares are entitled to vote at all meetings of our shareholders, with each share having one vote.

Our board of directors must call an annual meeting of shareholders to be held not later than 15 months after the last preceding annual meeting of shareholders and may, at any time, call a special meeting of shareholders. For purposes of determining the shareholders who are entitled to receive notice of a meeting of shareholders, the board of directors may, in accordance with the Business Corporations Act (Alberta) and National Instrument 54-101, fix in advance a date as the record date for that determination of shareholders, but that record date may not be more than 50 days or less than 35 days before the date on which the meeting is to be held.

The guidelines of National Instrument 54-101 and the provisions of the Business Corporations Act (Alberta) provide that notice of the time and place of a meeting of shareholders must be sent to each shareholder entitled to vote at the meeting, each director and to our auditors, not more than 50 days and not less than 21 days prior to the meeting. Our Bylaws provide that a quorum of shareholders is present at a meeting if at least 5% of the shares entitled to vote at a meeting are present in person or by proxy. A shareholder may participate in a meeting by

Index to Financial Statements

means of telephone or other communication facilities that permit all persons participating in the meeting to hear each other.

In the case of joint shareholders, one of the holders present at a meeting may, in the absence of the other holder(s) of the shares, vote the shares. If two or more joint shareholders are present in person or by proxy, then they are to vote as one on the shares held jointly by them. If there is a disagreement between joint shareholders, they are considered to have abstained from voting.

Amendments to Articles of Incorporation and Bylaws

An amendment to our articles of incorporation requires the approval of not less than two-thirds of the votes cast by the holders of our common shares at a meeting of the shareholders.

An amendment to our Bylaws requires the approval of not less than 51% of the votes cast by the holders of our common shares at a meeting of the shareholders.

Dividends

Our shareholders are entitled to receive such dividends and other distributions on the our common shares as the board of directors declares from time to time. Pursuant to the provisions of the Business Corporations Act (Alberta), we may not declare or pay a dividend if there are reasonable grounds for believing that (1) we are, or would after the payment be, unable to pay our liabilities as they become due or (2) the realizable value of our assets would thereby be less than the aggregate of our liabilities and stated capital of all classes. We may pay a dividend by issuing fully paid shares, or in money or property. If shares of a subsidiary or affiliate of Gastar are issued in payment of a dividend, the declared amount of the dividend stated as an amount of money will be added to the stated capital account maintained or to be maintained for shares of the class or series issued in payment of the dividend. We do not expect to pay any dividends to our shareholders for the foreseeable future, but intend to retain any future earnings for our operational and other cash needs. Further, our current senior secured notes prohibit us from paying cash dividends for so long as the notes remain outstanding.

No Preemption Rights; Limited Restrictions on Directors’ Authority to Issue Shares

Existing shareholders have no rights of preemption or first refusal under our articles of incorporation or under the laws of Alberta with respect to future issuances of our common shares. Subject to the policies of The Toronto Stock Exchange, our board of directors has the authority to issue additional common shares. The policies of The Toronto Stock Exchange stipulate that the issuance price must not be lower than the market price, less the maximum prescribed discount (which varies based on the market price), and that an exercise or conversion price of convertible securities must not be lower than the market price on the date of the issuance of the security.

Board of Directors; Election and Removal of Directors

Holders of our common shares at each annual general meeting of shareholders are required to elect directors to hold office for a term expiring not later than the close of the next annual general meeting of shareholders unless a director resigns, dies or is required to resign pursuant to a regulatory ruling (for example, if a director has violated disclosure or insider reporting provisions of the applicable securities laws and has received regulatory penalties for such violations which include prohibiting the director from serving on the board). The board of directors may fill vacancies and, as provided by our articles of incorporation, may also appoint additional directors between annual general meetings of shareholders, but the number of additional directors so appointed may not exceed the number that is one-third of the number of directors appointed at the last annual general meeting of shareholders.

At least half of our directors must be resident Canadians, unless we earn less than 5% of our consolidated gross revenues (as shown in our consolidated financial statements as at the end of our more recently completed

Index to Financial Statements

financial period) in Canada, in which case at least one-third of our directors must be resident Canadians. For the fiscal year ending December 31, 2004, we derived less than 5% of our consolidated gross revenues from sources in Canada; consequently, only one-third of our directors are required to be resident Canadians.

Any director may convene a meeting of directors. A minimum of 48 hours notice must be given before a meeting of directors. A majority of the directors constitutes a quorum at a meeting of directors. Every resolution submitted to a meeting of directors is decided by a vote of a majority of the directors participating in the meeting and the declaration of the chairman of the meeting on the result of the vote is final. In the case of a tie vote, the chairman does not have a tie-breaking vote.

Conflicts of Interest

A director who is a party to a material contract or proposed material contract with Gastar, or who has a material interest in any person who is a party to a material contract or proposed material contract with Gastar, is required to disclose in writing to us or request to have entered in the minutes of meetings of the directors the nature and extent of his interest.

A director who has a material interest in a material contract or proposed material contract with Gastar cannot vote on any resolution to approve the contract unless the contract is:

•

An arrangement by way of security for money lent to or obligations undertaken by him, or by a body corporate in which he has an interest, for the benefit of Gastar or an affiliate;

•

A contract relating primarily to his remuneration as a director, officer, employee or agent of Gastar or an affiliate;

•

A contract for indemnity or insurance; or

•

A contract with an affiliate.

Subject to a solvency test imposed by the Business Corporations Act (Alberta) and to the U.S. securities laws described below, we may give financial assistance by means of a loan, guarantee or otherwise to:

•

Any person on account of expenditures incurred or to be incurred on behalf of Gastar; and

•

To employees of Gastar or any of its affiliates to enable or assist them to purchase accommodation for their occupation.

•

In accordance with a share purchase or option scheme.

The fact that a person is a director does not prevent Gastar from providing him with such financial assistance if the director would otherwise qualify for it.

Under the U.S. securities laws, we are prohibited from directly or indirectly extending or maintaining credit, arranging for the extension of credit or renewing an extension of credit, in the form of a personal loan to or for any of the directors or executive officers of Gastar, except in certain circumstances. This prohibition does not apply to extensions of credit maintained by Gastar on July 30, 2002, but applies to any renewal or material modification of such existing credit.

Anti-takeover Laws

In Canada, takeovers are governed by provincial securities laws and the rules of applicable stock exchanges. While the rules may vary among the provinces, a party who acquires 10% of the voting or equity securities of any class of a company will generally be deemed to be an insider of that company and will, among other things, be required to file both a news release and a prescribed form with applicable provincial regulatory authorities.

Index to Financial Statements

The purchaser (including any party acting jointly or in concert with the purchaser) will be prohibited from purchasing any additional securities of the class of the target company previously acquired for a period commencing on the occurrence of an event triggering the filing requirement and ending on the expiry of one business day following the filing. This filing process, and the associated prohibition on further acquisition, will also apply in respect of every additional 2% or more of the target company’s securities of the same class that are subsequently acquired, provided that the prohibition on further acquisition does not apply to a purchaser that owns 20% or more of the outstanding securities of that class.

An offer to acquire outstanding voting or equity securities of a class, where the securities subject to the offer, together with the offeror’s securities, constitute in the aggregate 20% or more of the outstanding securities of that class of securities at the date of the offer, will trigger the take-over bid provisions of applicable provincial securities legislation (and, if applicable, the rules of applicable stock exchange(s)). Unless the bid is otherwise exempt, a take-over bid will require the bidder to prepare and mail to each shareholder a circular outlining the details of the bid and instructions regarding the tendering of the target shares. While a target company will generally provide a shareholder list to a bidder, there may be circumstances in which the bidder will need to go to court to obtain one, resulting in a delay in the process. Each shareholder must be offered the same consideration for its shares and the offer must be left open for at least 35 days. Depending on the circumstances and the parties involved, valuations of the target company and its operations may be required in support of the bid.

In addition to the foregoing, certain other Canadian legislation may limit a Canadian or non-Canadian entity’s ability to acquire control over or a significant interest in us, including the Competition Act (Canada) and the Investment Canada Act (Canada). Issuers may also approve and adopt shareholder rights plans or other defensive tactics designed to be triggered upon the commencement of an unsolicited bid and make the company a less desirable take-over target.

Limitation of Liability and Indemnification

The Business Corporations Act (Alberta) and our bylaws provide that we will indemnify each of our directors and officers and any person who acts or acted at our request as a director or officer of a body corporate of which we are or were a shareholder or creditor, and the heirs and legal representatives of each of them, against all costs, charges and expenses reasonably incurred by such director, officer or person, and their respective heirs or legal representatives, in respect of any action or proceeding to which any of them is made a party by reason of such director, officer or person being or having served in that position, if: (1) the director, officer or person acted honestly and in good faith with a view to the best interests of us; and (2) in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, the director, officer or person had reasonable grounds for believing that his conduct was lawful. As used above, “costs, charges and expenses” includes but is not limited to the fees, charges and disbursements or legal counsel on an as-between-a solicitor-and-the-solicitor’s-own-client basis and an amount paid to settle an action or satisfy a judgment. These indemnities will continue in effect after the director or officer resigns his position or his position is terminated for any reason.

We have also entered into indemnification agreements with our directors and executive officers as described above in “Management—Executive Compensation—Indemnification of Officers and Directors”.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling us under the indemnification arrangements described above, the SEC is of the opinion that this indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

Voluntary Liquidation and Dissolution

If we are depleted of resources and unable to meet our liabilities and ongoing continuous disclosure obligations under the Business Corporations Act (Alberta), our directors may propose, or a shareholder who is

Index to Financial Statements

entitled to vote at an annual general meeting of shareholders may make a proposal for the voluntary liquidation and dissolution of Gastar.

A company may liquidate and dissolve upon receiving the approval of the shareholders by special resolution at a meeting duly called and held. Approval of a special resolution requires the affirmative vote of not less than two-thirds of the votes cast by the shareholders present at the meeting or by proxy.

Upon shareholder approval of dissolution by special resolution, the company would discharge all of its liabilities and thereafter distribute all of the assets remaining, if any, pro rata to all of the shareholders of the company. Articles of Dissolution would then be sent to the Registrar appointed under the Business Corporations Act (Alberta) and the Registrar would issue a Certificate of Dissolution. The company would cease to exist on the date shown in the Certificate of Dissolution.

Listing

Our common shares are listed on The Toronto Stock Exchange under the symbol “YGA” (“YGA.TO in the U.S.) and may be traded in the United States on the over-the-counter market under the symbol, “GSREF.PK”.

Transfer Agent and Registrar

The transfer agent and registrar for our common shares are CIBC Mellon Trust Company, at its principal office in Toronto, Ontario at 200 Queen Quay East, Unit 6, Toronto, Ontario, M5A 4K9.

Tax Issues

For a discussion of the material Canadian and U.S. federal income tax considerations, including withholding provisions and applicable treaties, associated with the ownership of our common shares by U.S. residents, please see “Material Income Tax Consequences”.

Other Canadian Laws Affecting U.S. Shareholders

There are no governmental laws, decrees or regulations in Canada relating to restrictions on the export or import of capital, or affecting the remittance of interest, dividends or other payments by us to non-residents of Canada. Dividends paid to U.S. tax residents, however, are subject to a 15% withholding tax (or a 5% withholding tax for dividends if the shareholder is a corporation owning at least 10% of the outstanding voting shares of the corporation) pursuant to Article X of the reciprocal tax treaty between Canada and the United States. Please see “Material Income Tax Consequences”.

There are no limitations specific to the rights of non-residents of Canada to hold or vote our common shares under the laws of Canada or the Province of Alberta, or in our articles of incorporation or bylaws, other than those imposed by the Investment Canada Act (Canada) as discussed below.

Non-Canadian investors who acquire a controlling interest in us may be subject to the Investment Canada Act (Canada), which governs the basis on which non-Canadians may invest in Canadian businesses. Under the Investment Canada Act (Canada), the acquisition of a majority of the voting interests of an entity (or of a majority of the undivided ownership interests in the voting shares of an entity that is a corporation) is deemed to be an acquisition of control of that entity. The acquisition of less than a majority but one-third or more of the voting shares of a corporation (or of an equivalent undivided ownership interest in the voting shares of the corporation) is presumed to be acquisition of control of that corporation unless it can be established that, on the acquisition, the corporation is not controlled in fact by the acquirer through the ownership of the voting shares. The acquisition of less than one-third of the voting shares of a corporation (or of an equivalent undivided ownership interest in the voting shares of the corporation) is deemed not to be acquisition of control of that corporation.

Index to Financial Statements

DESCRIPTION OF INDEBTEDNESS

Senior Secured Notes

On June 17, 2005, we issued senior secured notes totaling $63.0 million in principal amount, together with the issuance of 1,217,269 of our common shares in a private placement transaction. The notes are secured by substantially all of our assets, bear interest at the sum of the three-month LIBOR rate plus 6%, payable quarterly, and mature on June 18, 2010. Additionally, we agreed to issue the purchasers of the senior secured notes for no additional consideration, additional shares in increments valued at CDN$4.5 million on each of the six, twelve and eighteen-anniversaries of the closing.

Pursuant to the senior secured notes, we have the right, on a quarterly basis during the period from two months after closing of the initial notes to 24 months after the same date, to require the note holders to purchase up to an aggregate additional $20.0 million principal amount of additional notes. The issuance of the additional notes is contingent upon compliance with a proved plus probable reserve PV(10) (“2P PV(10)”) to net senior secured debt coverage ratio of 2.0:1 and other covenants. Under the senior secured note agreement, the PV(10) valuation is to be based on a third party independent reserve report utilizing constant pricing based on the lower of current natural gas and oil prices, adjusted for area basis differentials, or $6.00 per Mcf of natural gas and $40.00 per barrel of oil. From the first anniversary of issuance up to the second anniversary of issuance of the note, proved reserves PV(10) (“1P PV10”) to net debt must be a minimum of 1.0:1. On the second anniversary date of the note, the 1P PV(10) reserve ratio covenant increases to a minimum of 1.5:1 and it increases to 2.0:1 on the third anniversary date and for all test periods thereafter until maturity. Utilizing the same reserve pricing criteria above, the 2P PV(10) to net debt reserve maintenance ratio covenant must be a minimum of 1.5:1 from date of issuance of the notes up to the first anniversary date. On the first anniversary date of the note, the 2P PV(10) reserve ratio covenant increases to a minimum of 2.5:1, on the second anniversary to 3.0:1 and on the third anniversary and for all test periods thereafter until maturity to 3.5:1. We must maintain compliance with the reserve ratio covenant at all future quarterly and annual covenant determination dates or be subject to mandatory principal redemptions under certain conditions.

Our bank deposit accounts are subject to account control agreements in favor of our senior lenders that allow the senior lenders to control our cash and use it to pay interest and/or principal outstanding related to the senior secured notes.

Unsecured Subordinated Notes

On June 17, 2005, in connection with our acquisition from Geostar of additional interests in the Deep Bossier area of East Texas and the Powder River Basin, we issued in a private placement $32.0 million of unsecured, subordinated notes to Geostar. On August 11, 2005, we executed an agreement with Geostar whereby the Geostar $32.0 million unsecured subordinated note was cancelled. In conjunction with the note cancellation, we agreed to issue Geostar $17.0 million of our common shares issued at a value of CDN$3.25 and a new unsecured subordinated note for $15.0 million. The new Geostar note bears interest, payable monthly commencing February 15, 2006, at three-month LIBOR plus 4.5% and matures November 15, 2006. The note requires monthly principal payments of $1.5 million commencing February 15, 2006 and continuing for nine months thereafter with a final principal payment of $1.5 million due on November 15, 2006. We may elect to pay interest in kind through the issuance of additional notes with such notes maturing on January 15, 2007.

In 2004, we completed the sale of $3.25 million of unsecured, subordinated notes. The notes mature between April and September 2009 and bear interest at 10% per annum paid semi-annually. These notes are callable by us after two years at various premiums as provided in the note purchase agreement. Additionally, the subscribers were issued 232,521 warrants exercisable at prices from CDN$3.64 and CND$4.18 and expiring between April and September 2009.

Index to Financial Statements

Convertible Debentures

On November 12, 2004, we issued $30.0 million aggregate principal amount of 9.75% convertible senior unsecured subordinated debentures in a private placement. The notes were issued pursuant to an indenture dated as of November 12, 2004 between Gastar and CIBC Mellon Trust Company. The net proceeds of the convertible debentures were used to accelerate our drilling in East Texas and otherwise to fund our operations.

The convertible debentures are payable in cash at maturity on November 20, 2009. The convertible debentures bear interest at a rate of 9.75% per annum, payable quarterly in arrears on each February 12, May 12, August 12 and November 12, commencing on February 12, 2005. The convertible debentures are convertible, in whole or in part, at the option of the holders at any time prior to the close of business on November 19, 2009 into common shares at a conversion price of $4.38 per share. Upon conversion, all accrued but unpaid interest thereon up to but not including the conversion date will be paid in cash to the surrendering holder.

The convertible debentures are not redeemable, in whole or in part, on or before November 13, 2006, except upon a defined change of control of us. At any time after November 13, 2006, we may redeem the convertible debentures, in whole or in part, on the terms and conditions set forth in the indenture at a redemption price equal to par plus accrued but unpaid interest thereon, provided that the weighted average price of our common shares on The Toronto Stock Exchange for any 20 consecutive trading days in any 30 consecutive 30-day period ending on the fifth trading day preceding notice of redemption is at least 130% of the conversion price then in effect.

Index to Financial Statements

SELLING SHAREHOLDERS

The selling shareholders may from time to time offer and sell pursuant to this prospectus all of the common shares covered by this prospectus, including shares issuable upon exercise of warrants, conversion of the convertible debentures and pursuant to subscription receipts. The selling shareholders may not offer or sell any of the warrants, convertible debentures or subscription receipts pursuant to this prospectus.

This prospectus has not been filed in respect of, and will not qualify, any distribution of the common shares covered by this prospectus in any province in the territory of Canada.

The following table sets forth certain information concerning the number of common shares beneficially owned by each of the selling shareholders. The first numerical column sets forth the number of common shares beneficially owned by each of the selling shareholders prior to this offering, assuming the full exercise of all warrants and the conversion of all convertible debentures held by such shareholder. The second numerical column sets forth the number of common shares being offered each selling shareholder pursuant to this prospectus. The third numerical column sets forth the number of common shares to be owned by each of the selling shareholders upon completion of this offering, assuming the sale of all common shares offered by this prospectus and the percentage of the class outstanding represented by such number of common shares.

We prepared this table based on the information furnished to us by the selling shareholders named in the table below, and we have not sought to verify such information. This table only reflects information regarding selling shareholders who furnished such information to us. We expect that we will update this table as we receive more information from shareholders who have not yet furnished the requested information to us. Information regarding selling shareholders not named as of the date hereof and information regarding transferees of named selling shareholders will be set forth in supplements to this prospectus or, if required by applicable law, amendments to the related registration statement, in each case upon request and provision of all required information to us. Information regarding named selling shareholders may change from time to time after the date of this prospectus. Any changed information will be set forth in prospectus supplements or, if required by applicable law, amendments to the related registration statement if and when necessary. In addition, upon our being notified by a selling shareholder that a donee or pledgee intends to sell more than 500 shares, we will file a supplement to this prospectus specifically naming such donee. No offer or sale pursuant to this prospectus may be made by a shareholder unless that holder is named in the table below, in a supplement to this prospectus or, if required by applicable law, in an amendment to the related registration statement that has become effective.

Any or all of the common shares offered hereby may be offered for sale pursuant to this prospectus by the selling shareholders from time to time. Please see “Plan of Distribution”. Accordingly, no estimate can be given as to the amounts of common shares that will be held by the selling shareholders upon consummation of any such sales. We have assumed for purposes of the table below that all of the selling shareholders will sell all of the common shares offered hereby pursuant to this prospectus. In addition, the selling shareholders named below may have sold, transferred or otherwise disposed of, in transactions exempt from the registration requirements of the Securities Act, all or a portion of their warrants, convertible debentures and subscription receipts and the underlying common shares since the date on which the information regarding their beneficial ownership of common shares was provided to us.

The percentage of common shares beneficially owned upon completion of this offering is based on 128,811,436 common shares outstanding as of August 1, 2005. Except as otherwise noted, beneficial ownership is determined in accordance with Rule 13d-3 under the Exchange Act. Accordingly, a person is deemed to be the beneficial owner of securities that can be acquired by that person within 60 days from August 1, 2005 upon the exercise of warrants or options or upon the conversion of the convertible debentures. Each beneficial owner’s percentage is determined by assuming that warrants or conversion rights that are held by that person, but not those held by any other person, and which are exercisable within 60 days from August 1, 2005, have been exercised. Unless otherwise indicated and subject to community property laws where applicable, we believe that

Index to Financial Statements

each selling shareholder has sole voting and investment power over all common shares reported as beneficially owned by such selling shareholder.

Except as set forth below, to our knowledge, none of the selling shareholders has, or within the past three years has had, a material relationship with us or any of our affiliates, other than their ownership of securities as described below. Unless otherwise noted, no selling shareholder would beneficially own 1% or more of the outstanding common shares following the sale of all shares offered hereunder.


	Number of Common Shares Beneficially Owned	Number of Common Shares Offered Hereunder	Number of Outstanding Common Shares Owned After Completion of Offering
E. William Richardson Trust (1)	25,000	25,000	-0-
Mary Lou Richardson Trust (1)	31,343	31,343	-0-
Patrick K. Magette Revocable Trust (1)	25,500	25,500	-0-
Rappaport Gamma, LP (1)	1,533,333	1,000,000	533,333
Donald Marquardt (1)	50,000	50,000	-0-
Michael E. & Christine A. Pacanowsky (1)	25,000	25,000	-0-
Edwin L. Wolff Revocable Trust (1)	100,313	30,000	70,313
Judith S. Hart Living Trust (1)	45,000	45,000	-0-
Robert R. & Ruth J. Fink (1)	59,120	25,000	34,120
Pete A. & Maureen P. Botting (1)	193,184	133,184	60,000
Monty A. & Paula S. Franssen Trust (1)	27,900	25,000	2,900
McCulloch Revocable Trust (1)	91,905	40,000	51,905
Leo J. & Jean E. Hertzog (1) (19)	2,144,928	144,928	2,000,000
Kevin Coccetti (1)	27,247	7,247	20,000
James & Nancy C. Hanna Jt. Ten (1)	7,169	7,169	-0-
John S. Poindexter III (1)	263,429	7,143	256,286
Matt & Sharlene Klein Trust (1)	38,023	3,301	34,722
Dr. Jose C. Jr. MD & Tina Dominguez, Jt. Ten. (1)	6,780	6,780	-0-
John E. & Lydia E. Oliva, Jt. Ten (1)	6,850	6,850	-0-
The Puls Family Trust (1)	7,143	7,143	-0-
Paul T. Hackspiel (1)	6,994	6,994	-0-
Clifford A. Cantrell Revocable Trust (1)	214,085	14,085	200,000
Carol A. Chaffin Revocable Trust (1)	7,093	7,093	-0-
Ingalls & Snyder LLC (2)	1,700,000	1,700,000	-0-
Westwind Partners Inc (3)	237,792	237,792	-0-
Prichard Capital Partners, LLC (4)	31,948	21,948	10,000
Donald Arthur Wright (5)	342,466	342,466	-0-
Middlemarch Partners Limited (6)	375,297	365,297	10,000
Sprott Asset Management Inc., for Sprott Canadian Equity Fund (6)	324,201	324,201	-0-
Aran Asset Management SA (7)	431,909	229,909	202,000
Global Gestion (6)	45,662	45,662	-0-
Front Street Investment Management Inc. (6)	73,059	73,059	-0-
North Pole Capital Master Fund (6)	559,361	559,361	-0-
Polaris Energy Offshore Master Fund (6)	159,817	159,817	-0-
Kings Road Investment Limited (8)	1,569,863	1,569,863	-0-
U.S. Global Investors Global Resources Fund (9)	1,142,466	942,466	200,000
Caerus Fund Ltd. (6) (18)	45,662	45,662	-0-
HFTP Investment LLC (10) (18)	2,185,426	2,185,426	-0-
Gaia Offshore Masterfund Ltd. (11) (18)	1,132,801	1,132,801	-0-
Leonardo, LP (12)	2,206,355	2,206,355	-0-

Index to Financial Statements


	Number of Common Shares Beneficially Owned	Number of Common Shares Offered Hereunder	Number of Outstanding Common Shares Owned After Completion of Offering
Wayland Recovery Fund, LLC (13)	440,837	440,837	-0-
Wayzata Recovery Fund, LLC (14)	265,023	265,023	-0-
Cyrus Opportunities Fund, LP (15)	83,469	83,469	-0-
Cyrus Opportunities Fund II, LP (16)	356,066	356,066	-0-
Fidelity Commonwealth Trust: Fidelity Small Cap Stock Fund	2,764,411	2,264,411	500,000
Fidelity Securities Fund: Fidelity Small Cap Value Fund	2,359,607	1,509,607	850,000
Byron A. Adams, Jr.	71,200	60,000	11,200
Advantage Advisors Catalyst Intl.	18,200	15,000	3,200
Advantage Advisors Catalyst Partners LP	24,000	20,000	4,000
Michael S. Needleman	10,000	10,000	-0-
Ironman Energy Capital, L.P.	280,000	280,000	-0-
Ridgecrest Partners L.P.	3,500	3,000	500
Ridgecrest Partners Ltd	14,400	12,000	2,400
Atlas Master Fund, Ltd	141,509	141,509	-0-
Grey K Fund, LP	56,604	56,604	-0-
Grey K Offshore Fund, Ltd.	84,905	84,905	-0-
Sanford B. Prater	20,000	20,000	-0-
Ridgecrest Partners QP, L.P.	89,900	80,000	9,900
Nite Capital LP	72,500	72,500	-0-
RAB Energy Fund Ltd	300,000	300,000	-0-
Any other holder of notes or future transferee, pledgee, donee, or successor of any such holder (17)	4,131,668	4,131,668	-0-

Total	29,089,223	24,022,444	5,066,779

(1)	Includes common shares issuable upon the exercise of warrants to purchase common shares exercisable, or upon conversion of 9.75% Convertible Senior Unsecured Debentures, within 60 days.

(2)

Represents 510,525 common shares issuable upon the exercise of warrants to purchase common shares and 1,989,475 common shares issuable upon the exercise of warrants to purchase common shares, all exercisable within 60 days. The warrants to purchase 510,525 common shares were issued to Ingalls & Snyder in connection with its purchase of $15 million in 15% senior unsecured notes in June 2004. The warrants to purchase 1,989,475 common shares were issued to Ingalls & Snyder in connection with its purchase of an additional $10 million in senior unsecured notes in October 2004.

(3)

Represents common shares issuable upon the exercise of warrants to purchase common shares exercisable within 60 days. These warrants to purchase common shares were issued to Westwind Partners Inc. who acted as a placement agent in connection with the Company’s issuance of its convertible senior unsecured debentures in November 2004. Westwind Partners Inc. also acted as a placement agent in connection with the Company’s private placement of common shares in June 2005.

(4)

Represents common shares issuable upon the exercise of warrants to purchase common shares exercisable within 60 days. These warrants to purchase common shares were issued to Pritchard Capital Partners, LLC who acted as a placement agent in connection with the Company’s issuance of its convertible senior unsecured debentures in November 2004. Pritchard Capital Partners, LLC also acted as a placement agent in connection with the Company’s private placement of common shares in June 2005 and also received a placement fee in connection with the Company’s issuance of $63 million in senior secured notes in June 2005.

(5)	Includes 342,466 common shares issuable upon the conversion of 9.75% Convertible Senior Unsecured Debentures, which are convertible within 60 days.

Index to Financial Statements

(6)	Represents common shares issuable upon the conversion of 9.75% Convertible Senior Unsecured Debentures, which are convertible within 60 days. Includes 68,493 common shares issuable upon the conversion of 9.75% Convertible Senior Unsecured Debentures, which are convertible within 60 days.

(7)	Includes 79,909 common shares issuable upon the conversion of 9.75% Convertible Senior Unsecured Debentures, which are convertible within 60 days.

(8)	Includes 1,369,863 common shares issuable upon the conversion of 9.75% Convertible Senior Unsecured Debentures, which are convertible within 60 days.

(9)	Includes 342,466 common shares issuable upon the conversion of 9.75% Convertible Senior Unsecured Debentures, which are convertible within 60 days.

(10)

Includes 684,931 common shares issuable upon the conversion of 9.75% Convertible Senior Unsecured Debentures, which are convertible within 60 days. Includes an estimated 1,172,026 common shares issuable pursuant to subscription receipts, which shares may be sold pursuant to this prospectus upon issuance.

(11)

Includes 426,941 common shares issuable upon the conversion of 9.75% Convertible Senior Unsecured Debentures, which are convertible within 60 days. Includes an estimated 551,286 common shares issuable pursuant to subscription receipts, which shares may be sold pursuant to this prospectus upon issuance.

(12)	Includes an estimated 1,723,312 common shares issuable pursuant to subscription receipts, which shares may be sold pursuant to this prospectus upon issuance.

(13)	Includes an estimated 344,228 common shares issuable pursuant to subscription receipts, which shares may be sold pursuant to this prospectus upon issuance.

(14)	Includes an estimated 207,058 common shares issuable pursuant to subscription receipts, which shares may be sold pursuant to this prospectus upon issuance.

(15)	Includes an estimated 65,113 common shares issuable pursuant to subscription receipts, which shares may be sold pursuant to this prospectus upon issuance.

(16)	Includes an estimated 277,813 common shares issuable pursuant to subscription receipts, which shares may be sold pursuant to this prospectus upon issuance.

(17)

Information about other selling shareholders will be set forth in one or more post-effective amendments, if required. Table assumes that these other shareholders, or any future transferees, pledges, donees, or successors of or from any such other holders in the table, do not beneficially own any common shares other than in respect of the securities pursuant to which the shares covered by this prospectus are issued.

(18)

Promethean Asset Management, LLC, a New York limited liability company (“Promethean”), serves as investment manager to HFTP Investment L.L.C. (“HFTP”), Gaia Offshore Master Fund, Ltd. (“Gaia”) and Caerus Fund Ltd. (“Caerus”) and may be deemed to share beneficial ownership of the securities beneficially owned by HFTP, Gaia and Caerus, as a result of Promethean’s power to vote and dispose of securities in each of HFTP, Gaia and Caerus. The ownership information for each of these three selling shareholders does not include the ownership information for the others. Promethean disclaims beneficial ownership of the securities beneficially owned by HFTP, Gaia and Caerus, and each of HFTP, Gaia and Caerus disclaims beneficial ownership of the securities beneficially owned by the others. James F. O’Brien, Jr. indirectly controls Promethean. Mr. O’Brien disclaims beneficial ownership of the securities beneficially owned by Promethean, HFTP, Gaia and Caerus.

(19)	Outstanding common shares owned after completion of the offering in full would constitute 1.55% of our outstanding common shares.

Index to Financial Statements

PLAN OF DISTRIBUTION

We are registering certain of our common shares that are either now outstanding or will be issued upon exercise of certain warrants, conversion of convertible debentures or the issuance of additional shares pursuant to subscription receipts issued to holders of our senior secured notes. We are also offering the opportunity to participate in the registration statement to other holders of some of our restricted securities. Shares covered in the registration will include common shares currently held by some holders and certain common shares to be issued in the future upon the exercise or conversion of our securities or pursuant to subscription receipts. We will not receive any of the proceeds of the sale of the common shares offered by this prospectus. The common shares may be sold from time to time to purchasers:

•

Directly by the selling shareholders; or

•

Through underwriters, broker-dealers or agents who may receive compensation in the form of discounts, concessions or commissions from the selling shareholders or the purchasers of the common shares from the selling shareholders.

The selling shareholders and any underwriters, brokers, dealers or agents that participate in the distribution of the common shares may be deemed to be “underwriters” within the meaning of the Securities Act, and any discounts, concessions, commissions or fees received by them and any profit on the resale of the common shares sold by them may be deemed to be underwriting discounts and commissions.

If the common shares are sold through underwriters or broker-dealers, the selling shareholders will be responsible for any underwriting discounts or commissions or agent’s commissions.

The common shares may be sold in one or more transactions at:

•

Fixed prices;

•

Prevailing market prices at the time of sale;

•

Prices related to prevailing market prices;

•

Varying prices determined at the time of sale; or

•

Negotiated prices.

These sales may be affected in transactions:

•

On any national securities exchange or quotation service on which the common shares may be listed or quoted at the time of the sale, including The Toronto Stock Exchange;

•

In the over-the-counter market;

•

In transactions otherwise than on such exchanges or services or in the over-the-counter market;

•

Through the writing and exercise of options, whether these options are listed on any options exchange or otherwise;

•

Through the settlement of short sales; or

•

Through any combination of the foregoing.

These transactions may include block transactions or crosses. Crosses are transactions in which the same broker acts as an agent on both sides of the trade. In connection with sales of the common shares, the selling shareholders may enter into hedging transactions with broker-dealers. These broker-dealers may in turn engage in short sales of the common shares in the course of hedging their positions. The selling shareholders may also sell the common shares short and deliver common shares to close out short positions provided that the short sales

Index to Financial Statements

are made after the registration statement is declared effective, or loan or pledge common shares to broker-dealers that in turn may sell the common shares.

To our knowledge, there are currently no plans, arrangements or understandings between any selling shareholders and any underwriter, broker-dealer or agent regarding the sale of the common shares by the selling shareholders. Selling shareholders may choose not to sell any or all of the common shares offered by them pursuant to this prospectus. In addition, we cannot assure you that any such selling shareholder will not transfer, devise or gift the common shares offered hereby by other means not described in this prospectus. Any common shares that qualify for sale pursuant to Rule 144 or Rule 144A under the Securities Act may be sold under Rule 144 or Rule 144A rather than pursuant to this prospectus. There can be no assurance that any selling shareholder will sell any or all of the common shares registered pursuant to this registration statement of which this prospectus forms a part.

Our common shares are listed for trading on The Toronto Stock Exchange under the symbol “YGA” and may be traded in the United States over-the-counter market under the symbol “GSREF.PK”.

The selling shareholders and any other person participating in such distribution will be subject to applicable provisions of the Exchange Act and the rules and regulations promulgated thereunder, including Regulation M, which may limit the timing of purchases and sales of any of common shares by the selling shareholders and any other participating person. In addition, Regulation M may restrict the ability of any person engaged in the distribution of the common shares to engage in market-making activities with respect to the common shares. This may affect the marketability of the common shares and the ability of any person or entity to engage in market-making activities with respect to common shares.

Pursuant to the subscription agreements with the selling shareholders who hold convertible debentures, the form of which subscription agreement is filed as an exhibit to the registration statement of which this prospectus forms a part, we may be indemnified by the selling shareholders against liabilities, including liabilities under the Securities Act, that may arise from any written information furnished to us by the selling shareholder specifically for use in this prospectus. Pursuant to the agency agreement, we will indemnify Westwind and its officers, directors, shareholders, agents, employees and advisors against certain liabilities, including some liabilities under the Securities Act, or they will be entitled to contribution. We may be indemnified by Westwind and its officers, directors, shareholders, agents, employees and advisors against certain liabilities, including liabilities that may arise under the Securities Act, in accordance with the agency agreement, or we may be entitled to contribution. We have also agreed to indemnify the selling shareholders that are holders of our senior secured notes and their officers, directors, shareholders, agents, employees and advisors against certain liabilities, including some liabilities under the Securities Act, or they will be entitled to contribution.

We have agreed to pay substantially all of the expenses incidental to the registration, offering and sale of the common shares covered by this prospectus to the public other than commissions, fees and discounts of underwriters, brokers, dealers and agents.

To comply with the securities laws of some jurisdictions, if applicable, the holders of common shares may offer and sell the common shares in such jurisdictions only through registered or licensed brokers or dealers. In addition, under certain circumstances, in some jurisdictions shares of the common shares may not be offered or sold unless they have been registered or qualified for sale in the applicable jurisdiction or an exemption from registration or qualification requirements is available and is complied with.

If required, at the time of a particular offering of common shares by a selling shareholder, a supplement to this prospectus will be circulated setting forth the name or names of any underwriters, broker-dealers or agents, any discounts, commissions or other terms constituting compensation for underwriters and any discounts, commissions or concessions allowed or reallowed or paid to agents or broker-dealers. We have no obligation to

Index to Financial Statements

any selling shareholder to arrange an underwriting, or assist in providing for any proposed sale, of any of the common shares offered hereby.

We have agreed with some of the selling shareholders to keep the registration statement of which this prospectus forms a part effective for specified periods of time or until the occurrence of certain events. We may under certain circumstances suspend the use of this prospectus, upon notice to the selling shareholders, to update the registration statement of which this prospectus forms a part with periodic information or material non-public information as required by the Securities Act. We have agreed with some of the selling shareholders to use our reasonable efforts to limit these suspended periods to those required by the Securities Act or limit them to contractually specified limits.

Once sold under the registration statement of which this prospectus forms a part, the common shares will be freely tradeable in the hands of persons other than our affiliates.

Index to Financial Statements

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Geostar is the beneficial owner of approximately 9.8% of our common shares. Thom Robinson serves as Chairman of the Board of Directors of Gastar and is an officer and director of Geostar.

On June 1, 2000, we entered into an agreement with Geostar, a significant shareholder, to settle accounts payable related to the development of natural gas and oil properties with the issuance of a floating convertible debenture for up to CDN$25.0 million. Under the agreement, Geostar would continue to provide funds for development and operations by allowing us to draw down on the debenture. Advances under the debenture were subject to Geostar’s availability of funds and the approval of the requested advances by Geostar’s board of directors. The debenture was payable in cash or convertible into common shares, at prevailing market prices at our option.

In 2001, we entered into a Participation and Operating Agreement, or POA, with Geostar. For the East Texas properties, the POA was replaced effective January 1, 2005 with a Joint Operating Agreement, or JOA. Pursuant to the terms of the original POA, which still governs West Virginia and certain of our Australian assets, we have the option to participate as a working interest partner in properties in which Geostar and its subsidiaries have interests in on an “at cost” basis, subject to our full due diligence review prior to our participation election. Upon agreeing to participate, we are responsible for its proportionate share of actual costs expended by Geostar and its subsidiaries to third parties on an “at cost” basis. The balances of $601,000 at December 31, 2004 and $39,000 at December 31, 2003 represented amounts owed to Geostar and its subsidiaries for natural gas and oil property development. The 2003 balance was settled in 2004 by cash payment. In 2004, pursuant to the terms of the POA, Geostar billed us $27,000 (2003—$369,000) for administrative overhead.

In 2004, we recorded $1.3 million in general and administrative costs for administrative and technical support provided by Geostar to us. Commencing April 1, 2004, we agreed with Geostar to replace the administrative fee with a cost sharing arrangement. As a result, Geostar charged us a proportionate amount of direct salary and shared premises rent expense for Geostar employees providing administrative and technical support services to us based on actual costs incurred. This cost sharing arrangement continued as long as Geostar is the operator of the properties. This arrangement resulted in 2004 charges of approximately $146,000 per month for the second and third quarter, $150,000 per month for the fourth quarter. We incurred approximately $115,000 in 2004 ($33,000 in 2003) of seismic reprocessing fees paid to a subsidiary of Geostar. The seismic reprocessing fees were capitalized to natural gas and oil properties.

Effective January 1, 2005, we entered into a JOA with Geostar covering an Area of Mutual Interest (“AMI”) in East Texas, with Gastar as a non-operator and Geostar as operator. Under the terms of the JOA, Geostar received overhead reimbursement equal to 12.5% of development costs for the first 10 wells drilled after the effective date, 10% of the development costs for the 11^th through 20^th wells and 8.5% of the developments costs for all subsequent wells. As a result, Geostar no longer charges us a proportionate amount of direct salary and shared premises rent expense for Geostar employees providing administrative and technical support services to us. At March 31, 2005, Geostar billed us $1.4 million, which was equal to 12.5% of development costs for the Greer #1 and F-K #2 wells. These amounts were paid subsequent to the end of the quarter. In conjunction with the execution of the JOA, we terminated the convertible debenture arrangement with Geostar and commenced operating the East Texas properties. Under the new arrangement, we are required to find financing for our share of future joint venture costs.

There is a balance of $2.7 million payable to Geostar as the operator pursuant to the JOA at March 31, 2005. Of the total revenue receivable at March 31, 2005, $3.0 million (2004—$1.6 million) represents amounts that were due from Geostar as operator of the properties, once Geostar received the revenue from the third party natural gas purchaser. These amounts were settled subsequent to the end of the quarter.

Concurrent with the private placement of senior secured notes on June 17, 2005, we closed the acquisition from Geostar of additional leasehold and working interest properties in the Hilltop area of East Texas and in the

Index to Financial Statements

Powder River Basin of Wyoming and Montana. We paid Geostar a total of $68.5 million for the interests acquired from Geostar consisting of $30.5 million in cash, 1,650,133 common shares valued at CDN$4.50 per share and $32.0 million in unsecured subordinated notes maturing on January 31, 2006. The acquisition increased our working interest position in the Hilltop area from an average of over 70% to an average of over 90% and gave us operational control of the properties. The acquisition of additional Powder River Basin interests increased our working interest position from approximately 17% to approximately 38% in properties currently being developed through an existing joint venture.

All related party transactions in the normal course of operations have been measured at the agreed to exchange amounts, which is the amount of consideration established and agreed to by the related parties and which is similar to those negotiated with third parties.

Index to Financial Statements

MATERIAL INCOME TAX CONSEQUENCES

A brief description of certain provisions of the tax treaty between Canada and the United States is included below, together with a brief discussion of certain taxes, including withholding provisions, to which U.S. shareholders are subject under existing laws and regulations of Canada and the United States. The consequences, if any, of state and local taxes are not considered. The following information is general and security holders should seek the advice of their own tax advisors, tax counsel or accountants with respect to the applicability or effect on their own individual circumstances of not only the matters referred to herein, but also any state or local taxes.

Canadian Federal Income Tax Consequences Associated with our Common Shares

General. The following is a summary of the principal Canadian federal income tax consequences generally applicable in respect of the ownership of our common shares. The tax consequences to any particular holder of our common shares will vary according to the status of that holder as an individual, trust, corporation or member of a partnership, the jurisdiction in which that holder is subject to taxation, the place where that holder is resident and, generally, that holder’s particular circumstances. This summary is applicable only to holders who are resident in the United States and are subject to United States tax, are not (and have never been) resident in Canada, hold their shares as capital property and do not (and will not) use or hold their shares in, or in the course of, carrying on business in Canada. For purposes of this discussion, a non-resident holder means a holder of our common shares who does not reside in Canada.

The following general discussion in respect of taxation is based upon management’s understanding of the rules. No opinion was requested by us, or has been provided by our counsel or auditors, with respect to the Canadian income tax consequences described in the following discussion.

Dividend Withholding. We have not paid dividends on our common shares in any of the past three years and have no plans to pay dividends in the foreseeable future. Canadian federal tax legislation would require a 25% withholding from any dividends paid or deemed to be paid to our non-resident shareholders. However, shareholders resident in the United States and subject to United States tax would generally have this rate reduced to 15% pursuant to the tax treaty between Canada and the United States. The withholding tax rate on the gross amount of dividends is reduced to 5% if the beneficial owner of the dividend is a U.S. corporation which owns at least 10% of our voting stock.

The amount of stock dividends paid to non-residents of Canada would be subject to withholding tax at the same rate as cash dividends. The amount of a stock dividend (for tax purposes) would generally be equal to the amount by which our paid-up capital had increased by reason of the payment of such dividend. We will furnish additional tax information to shareholders in the event of such a stock dividend.

Capital Gains. A non-resident who holds common shares as capital property generally will not be subject to Canadian taxes on capital gains realized on the disposition of such shares unless the shares are “taxable Canadian property” within the meaning of the Income Tax Act (Canada), and no relief is afforded under any applicable tax treaty. Common shares generally will not be taxable Canadian property of a shareholder of us unless, at any time during the five-year period immediately preceding a disposition of such shares, not less than 25% of the issued shares of any class or series of our capital stock belonged to persons with whom the shareholder did not deal at arm’s length, or to the shareholder together with such persons or unless the shares were acquired by the holder in one of several tax deferred exchanges for shares which were themselves taxable Canadian property.

A non-resident shareholder whose common shares constitute taxable Canadian property and who is a resident of the United States for purposes of the tax treaty between Canada and the United States generally would be exempt from Canadian tax on any capital gain realized on a disposition of those shares in any event, provided the shares do not derive their value primarily from Canadian real property (including Canadian resource

Index to Financial Statements

properties). Management is of the view that common shares do not derive their value primarily from Canadian real property.

United States Federal Income Tax Consequences Associated with our Common Stock

The following is a general discussion of certain U.S. federal income tax consequences that may apply to a holder of our common shares. This discussion is based on the Internal Revenue Code of 1986, as amended, which we refer to as the Code, Treasury Department regulations promulgated under the Code, published Internal Revenue Service, or IRS, rulings, published administrative positions of the IRS, and court decisions that are currently applicable, any or all of which could materially and adversely change at any time, possibly on a retroactive basis. In addition, the discussion does not consider the potential effects, both adverse and beneficial, of any proposed legislation which, if enacted, could be applied at any time, possibly on a retroactive basis. The following discussion is not intended to be, nor should it be construed to be, legal or tax advice to any holder or prospective holder of our common shares. No opinion was requested by us, or is provided by our counsel, with respect to the U.S. federal income tax consequences described in the following discussion. Accordingly, holders and prospective holders of our common shares should consult their own tax advisors about the U.S. federal, state, local and Non-U.S. tax consequences of purchasing, owning and disposing of our common shares.

United States Federal Income Taxation of U.S. Holders. As used in this discussion, a “U.S. Holder” means a holder of our common shares who is (1) a citizen or individual resident of the United States, (2) a corporation or entity taxable as a corporation for U.S. federal income tax purposes that is created or organized in or under the laws of the United States or of any political subdivision thereof or the District of Columbia, (3) an estate whose income is taxable in the United states irrespective of source or (4) a trust if a court within the United States is able to exercise primary jurisdiction over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust.

This summary does not address the tax consequences to, and U.S. Holder does not include, persons subject to specific provisions of federal income tax law, such as tax-exempt organizations, qualified retirement plans, individual retirement accounts and other tax-deferred accounts, financial institutions, insurance companies, real estate investment trusts, regulated investment companies, broker-dealers, persons or entities that have a “functional currency” other than the U.S. Dollar, shareholders subject to the alternative minimum tax, shareholders who hold our common shares as part of a straddle, hedging or a conversion transaction, constructive sale or other arrangement involving more than one position, partners and other pass-through entities and persons holding an interest in such entities, and shareholders who acquired their common shares through the exercise of employee stock options or otherwise as compensation for services. This summary is limited to U.S. Holders who own our common shares as capital assets (generally, property held for investment). This summary does not address the consequences to a person or entity holding an interest in a shareholder or the consequences to a person of the ownership, exercise or disposition of any options, warrants or other rights to acquire our common shares. If a partnership (including an entity treated as a partnership for U.S. federal income tax purposes) holds our common shares, the tax treatment of a partner generally will depend upon the status of the partner and upon the activities of the partnership. If you are a partnership, or a partner in a partnership, holding common shares, you should consult your tax advisor.

Distributions on Our Common Shares. We have never paid any cash dividends on our common shares and do not anticipate paying any cash dividends in the foreseeable future. However, if U.S. Holders receive dividend distributions (including constructive dividends) with respect to our common shares such holders would be required to include in gross income for U.S. federal income tax purposes the gross amount of such distributions equal to the U.S. Dollar value of such distributions on the date of receipt (based on the exchange rate on such date) to the extent that we have current or accumulated earnings and profits, without reduction for any Canadian income tax withheld from such distributions. Such Canadian tax withheld may be credited, subject to certain limitations, against the U.S. Holder’s U.S. federal income tax liability or, alternatively, may be deducted in computing the U.S. Holder’s U.S. federal taxable income by those who itemize deductions. See “Foreign Tax

Index to Financial Statements

Credit”, below. To the extent that distributions exceed our current or accumulated earnings and profits, they will be treated first as a return of capital up to the U.S. Holder’s adjusted basis in our common shares (and not subject to tax) and thereafter as gain from the sale or exchange of the common shares (which is taxable as capital gain). Subject to certain exceptions, dividends paid on our common shares generally will not be eligible for the dividends-received deduction available to corporations receiving dividends from certain United States corporations.

Dividends , if any, paid on our common shares to a U.S. Holder who is an individual, trust or estate (a “U.S. Individual Holder”) will be treated as “qualified dividend income” that is taxable to such U.S. Individual Holder at preferential rates (through 2008) provided that (i) we are eligible for the benefits of a comprehensive income tax treaty with the United States that has been determined to be satisfactory for this purpose (the U.S.-Canadian Treaty is included for this purpose); (ii) we are not a passive foreign investment company or “PFIC” for the taxable year during which the dividend is paid or the immediately preceding taxable year (which we do not believe we are or have been or will be); (iii) the U.S. Individual Holder has owned the common shares for more than 60 days in the 121-day period beginning 60 days before the date on which the common shares become ex-dividend; and (iv) the U.S. Individual Holder is not under an obligation to make related payments with respect to positions in substantially similar or related property.

Special rules may apply to any “extraordinary dividend” paid by us. An extraordinary dividend is, generally, a dividend equal to or in excess of 10 percent of a shareholder’s adjusted basis (or fair market value in certain circumstances) in a share of common stock. If we pay an “extraordinary dividend” on our common shares that is treated as “qualified dividend income”, then any loss derived by a U.S. Individual Holder from the sale or exchange of common shares will be treated as long-term capital loss to the extent of such dividend.

Foreign Tax Credit. A U.S. Holder who pays (or has withheld from distributions) Canadian income tax with respect to the ownership of our common shares may be entitled, at his or her option, to either a deduction or a tax credit for such foreign tax paid or withheld. Furthermore, a U.S. Holder that is a domestic corporation that owns 10% or more of our voting stock may be eligible to claim a deemed paid foreign tax credit based on the underlying non-U.S. income taxes paid by us. Generally, it will be more advantageous to claim a credit because a credit reduces U.S. federal income taxes on a dollar-for-dollar basis, while a deduction merely reduces the taxpayer’s income subject to tax. This election is made on a year-by-year basis and applies to all foreign income taxes (or taxes in lieu of income tax) paid by (or withheld from) the U.S. Holder during the year.

There are significant and complex limitations which apply to the foreign tax credit, among which is the general limitation that the credit cannot exceed the proportionate share of the U.S. Holder’s U.S. federal income tax liability that the U.S. Holder’s foreign source income bears to his or her or our worldwide taxable income. There are further limitations based on the type of income. In addition, any foreign tax credits may also be subject to special treaty limitations. The availability of the foreign tax credit, the deemed paid foreign tax credit, and the application of the limitations on the credit are fact-specific and holders and prospective holders of our common shares should consult their own tax advisors regarding their individual circumstances.

Sale, Exchange or other Disposition of Common Shares. Assuming we do not constitute a PFIC for any taxable year, a U.S. Holder generally will recognize taxable gain or loss upon a sale, exchange or other disposition of our common shares in an amount equal to the difference between the amount realized by the U.S. Holder from such sale, exchange or other disposition and the U.S. Holder’s tax basis in such shares. Subject to the discussion of extraordinary dividends above, such gain or loss will be treated as long-term capital gain or loss if the U.S. Holder’s holding period is greater than one year at the time of the sale, exchange or other disposition. Preferential tax rates for long term capital gains may apply to certain U.S. Holders who satisfy minimum holding period and other requirements. There are currently no preferential tax rates for long term capital gains for any U.S. Holder that is a corporation. A U.S. Holder’s ability to deduct capital losses is subject to certain limitations.

Index to Financial Statements

Special Rules. In the following circumstances, the above sections of the discussion may not describe the U.S. federal income tax consequences resulting from the holding, receipt of dividends and disposition of common shares. Management does not believe that we are a “PFIC”, or a “controlled foreign corporation” as those terms are defined below.

Passive Foreign Investment Company. A non-U.S. entity treated a corporation for U.S. federal income tax purposes will be a PFIC in any taxable year in which, after taking into account the income and assets of the corporation and certain subsidiaries pursuant to a “look through” rule, either (i) 75% or more of its gross income is “passive income” such as interest, dividends and certain rents and royalties or (2) at least 50% of the average value of its assets is attributable to assets that produce passive income or are held for the production of passive income. Management does not believe that we are a PFIC, or will be a PFIC in the future, because we are engaged primarily in the business of a natural gas and oil exploration and development. We have not received 75% or more of our gross income from passive sources, nor has 50% or more of the fair market value of our assets been held for the production of passive income. The taxation of a U.S. shareholder who owns stock in a PFIC is extremely complex and is beyond the scope of this discussion. U.S. persons should consult with their own tax advisors regarding the impact of these rules if we are or were to become a PFIC.

Controlled Foreign Corporation. A controlled foreign corporation or CFC is a foreign corporation more than 50% of the stock of which, by vote or value, is owned, directly, indirectly or constructively, by one or more U.S. shareholders who each owns, directly, indirectly or constructively, 10% or more of the total combined voting power of all classes of stock of the foreign corporation (each a “CFC Shareholder”). If we are a CFC, a CFC Shareholder would be treated as receiving current distributions of an allocable share of certain types of income. Additionally, such a CFC Shareholder would recognize ordinary income to the extent of an allocable share of our earnings and profits, rather than capital gain, on the sale of his or her common shares. Management does not believe that we are a CFC because shareholders who directly, indirectly or constructively control 10% or more of the total voting power of our outstanding common shares do not own more than 50% of our common shares.

United States Federal Income Taxation of Non-U.S. Holders. For purposes of this discussion, a beneficial owner of our common shares that is not a U.S. Holder (other than a partnership or entity treated as a partnership for U.S. federal income tax purposes) is a Non-U.S. Holder.

Distributions on our Common Shares. Distributions we pay to a Non-U.S. Holder will not be subject to U.S. federal income tax or withholding tax if the Non-U.S. Holder is not engaged in a U.S. trade or business. If the Non-U.S. Holder is engaged in a U.S. trade or business, distributions we pay will be subject to U.S. federal income tax at regular graduated rates if those distributions are effectively connected with that Non-U.S. Holder’s U.S. trade or business and, if an income tax treaty applies, are attributable to a permanent establishment maintained by that Non-U.S. Holder in the United States. In addition, a “branch profits tax” may be imposed at a 30% rate, or a lower rate under an applicable income tax treaty, on dividends received by a non-U.S. corporation that are effectively connected with its conduct of a trade or business in the United States.

Sale, Exchange or other Disposition of Common Shares. Non-U.S. Holders generally will not be taxed on any gain recognized on a disposition of our common stock unless the gain is effectively connected with the Non-U.S. Holder’s conduct of a trade or business in the United States and, if an income tax treaty applies, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States. If the Non-U.S. Holder is engaged in a U.S. trade or business and the gain is effectively connected with that trade or business (and if a tax treaty applies, is attributable to a permanent establishment maintained by such Non-U.S. Holder in the United States), such gain will be subject to U.S. federal income tax at regular graduated rates and, if the Non-U.S. Holder is a corporation, the branch profits tax described above may also apply. A Non-U.S. Holder who is an individual and who is present in the United States for 183 days or more in the taxable year of the disposition and meets other requirements also will be subject to U.S. federal income tax on gain recognized on a disposition of our common stock.

Index to Financial Statements

Information Reporting and Backup Withholding Tax. In general, dividend payments or other taxable distributions made within the United States will be subject to information reporting and U.S. backup withholding tax if a U.S Individual Holder fails to provide an accurate taxpayer identification number certified under penalties of perjury, as well as certain other information or otherwise establish an exemption from backup withholding.

Non-U.S. Holders may be required to establish their exemption from information reporting and backup withholding by certifying their status on an IRS Form W-8BEN, W-8ECI or W-8IMY as applicable.

If a Non-U.S. Holder sells shares to or through the U.S. office of a U.S. or foreign broker, the payment of the proceeds generally will be subject to information reporting requirements and backup withholding unless the Non-U.S. Holder properly certifies its non-U.S. status under penalties of perjury or otherwise establishes an exemption. Information reporting requirements and backup withholding generally will not apply to any payment of the proceeds of the sale of common shares affected outside the United States by a foreign office of a broker. However, U.S. information reporting requirements (but not backup withholding requirements) will apply to payment of the sales proceeds if the broker is a United States person or has certain other contacts with the United States.

Backup withholding is not an additional tax. Rather, a holder generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed such holder’s U.S. federal income tax liability by timely filing a properly completed claim for refund with the U.S. Internal Revenue Service.

LEGAL MATTERS

The validity of the common shares offered by this prospectus will be passed upon for us by Burnet, Duckworth & Palmer LLP.

EXPERTS

Our consolidated financial statements as of and for each of the three years in the period ended December 31, 2004 included in this prospectus have been audited by BDO Dunwoody LLP, chartered accountants, as stated in their report appearing herein and elsewhere in this registration statement, and have been so included in reliance upon the report of such firm given upon their authority as experts in auditing and accounting.

Information included in this prospectus regarding our estimated quantities of natural gas and oil reserves were prepared by us. Our proved reserve estimates as of December 31, 2004, 2003 and 2002 included in this prospectus were prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers.

Index to Financial Statements

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding the common shares. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common shares offered by this prospectus, you may desire to review the full registration statement, including its exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E, Room 1580, Washington, D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at 100 F Street, N.E, Room 1580, Washington, D.C. 20549, at prescribed rates or from the SEC’s web site on the Internet at http://www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on public reference rooms.

As a result of the offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website on the Internet is located at http://www.gastar.com and we expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

We intend to furnish or make available to our shareholders annual reports containing our audited financial statements prepared in accordance with U.S. GAAP. We also intend to furnish or make available to our shareholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

Index to Financial Statements

GASTAR EXPLORATION LTD.

INDEX TO FINANCIAL STATEMENTS


		Page
CONSOLIDATED FINANCIAL STATEMENTS FOR THE FISCAL YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets as of December 31, 2004 and 2003 and as of March 31, 2005		F-3

Consolidated Statements of Operations for the years ended December 31, 2004, 2003 and 2002 and the three months ended March 31, 2005 and 2004		F-4

Consolidated Statements of Changes in Shareholders’ Equity and Comprehensive Loss for the years ended December 31, 2004, 2003 and 2002		F-5

Consolidated Statements Changes Shareholders’ Equity and Comprehensive Loss for the three months ended March 31, 2005 and 2004		F-6

Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002 and the three months ended March 31, 2005 and 2004		F-7

Notes to Consolidated Financial Statements		F-8-39

F-1

Index to Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Gastar Exploration Ltd.

We have audited the accompanying consolidated balance sheets of Gastar Exploration Ltd. and subsidiaries (the “Company”) as of December 31, 2004 and 2003 and the related consolidated statements of operations, stockholders’ equity and comprehensive loss and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the Standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gastar Exploration Ltd. and subsidiaries at December 31, 2004 and 2003 and the consolidated results of their statements of loss, stockholders’ equity and comprehensive loss and cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2, the Company, effective January 1, 2003, adopted SFAS No. 143 regarding asset retirement obligation recognition.

BDO Dunwoody LLP

Calgary, Alberta

March 18, 2005 (August 11, 2005 as to Note 21)

The accompanying notes are an integral part of these consolidated financial statements

F-2

Index to Financial Statements

GASTAR EXPLORATION LTD.

CONSOLIDATED BALANCE SHEETS


	As of March 31, 2005			As of December 31,
	As of March 31, 2005			2004			2003
	(unaudited)
	(in thousands)
Assets
Current
Cash	$	4,546		$	15,842		$	681
Revenue receivable (Note 16(c))		3,198			1,693			—
Accounts receivable		26			38			237
Prepaid expenses		177			307			157
Current portion of deferred charges (Note 5)		170			238			—

		8,117			18,118			1,075
Deferred charges (Note 5)		3,155			3,442			400
Cash call receivable (Note 3)		5,339			6,318			1,220
Property and equipment (Note 4)		63,459			56,564			35,799
Site restoration bond		—			—			263

	$	80,070		$	84,442		$	38,757

Liabilities and Shareholders’ Equity
Current
Accounts payable and accrued liabilities	$	2,144		$	1,197		$	600
Accounts payable – joint venture partner (Note 16(c))		2,673			601			—
Commitments payable (Note 18(f) and (g))		—			—			1,343
Current portion of contract payable (Note 6)		—			—			1,000
Current portion of convertible notes (Note 8)		—			—			1,552

		4,817			1,798			4,495

Long Term
Accrued liability (Note 5(b))		77			77			—
Drilling advances liability (Note 9)		—			1,002			3,008
Senior notes (Note 11)		24,989			24,840			—
Subordinated, unsecured notes payable (Note 10)		3,050			3,038			—
Convertible notes (Note 8)		30,000			30,000			—
Asset retirement obligation (Note 7)		1,980			1,711			984

		64,913			62,466			8,487

Debt to be Settled by the Issuance of Shares
Due to related party (Notes 16(a))		—			—			39
Convertible notes (Note 8)		—			—			6,562

		—			—			6,601

Commitments and Contingencies (Note 18)

Shareholders’ Equity
Common stock (Note 13)		49,804			49,780			40,071
Additional paid-in capital (Note 14)		2,167			1,374			—
Other comprehensive loss		(95	)		(95	)		(95	)
Deficit		(36,719	)		(29,083	)		(16,307	)

		15,157			21,976			23,669

	$	80,070		$	84,442		$	38,757

The accompanying notes are an integral part of these consolidated financial statements

F-3

Index to Financial Statements

GASTAR EXPLORATION LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS


	For the Three Months Ended March 31,						For the Years Ended December 31,
	2005			2004			2004			2003			2002
	(unaudited)
	(in thousands, except share and per share data)
Revenues	$	4,731		$	356		$	6,059		$	1,461		$	783

Expenses
Depletion, depreciation and amortization		2,690			176			3,233			572			360
Impairment of natural gas and oil properties		4,410			—			6,306			552			377
Interest and debt related items (Note 12)		2,153			419			3,248			2,567			2,043
Accretion on asset retirement obligation (Note 7)		19			13			52			54			—
Mineral resource properties		29			31			32			30			1
Lease operating, transportation and selling		1,315			211			2,000			712			769
General and administrative		1,765			167			4,023			1,909			1,933

Net loss before other items		(7,650	)		(661	)		(12,835	)		(4,935	)		(4,700	)

Other items
Investment income and other		40			4			56			18			17
Foreign exchange gain (loss)		(26	)		(13	)		3			91			84

		14			(9	)		59			109			101

Net loss before income taxes and cumulative effect of change in accounting principle		(7,636	)		(670	)		(12,776	)		(4,826	)		(4,599	)
Provision for income taxes (Note 17)		—			—			—			—			—

Net loss before cumulative effect of change in accounting principle		(7,636	)		(670	)		(12,776	)		(4,826	)		(4,599	)
Cumulative effect of change in accounting principle, net of tax ($nil) (Note 2(p))		—			—			—			(121	)		—

Net loss	$	(7,636	)	$	(670	)	$	(12,776	)	$	(4,947	)	$	(4,599	)

Loss per share (Note 15)
Net loss per share before cumulative effect of change in accounting principle (basic and diluted)	$	(0.067	)	$	(0.006	)	$	(0.115	)	$	(0.046	)	$	(0.047	)
Net loss per share (basic and diluted)	$	(0.067	)	$	(0.006	)	$	(0.115	)	$	(0.047	)	$	(0.047	)

Weighted average shares outstanding
Basic and diluted		113,788,198			107,265,493			111,374,446			104,958,180			98,617,920

The accompanying notes are an integral part of these consolidated financial statements

F-4

Index to Financial Statements

GASTAR EXPLORATION LTD.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY AND COMPREHENSIVE LOSS


	Shares Issued		Common Stock			Additional paid-in capital		Other Comprehensive (loss)			Retained Deficit			Total Shareholders’ Equity
	(in thousands, except share data)
For the Years Ended December 31, 2002, 2003 and 2004:

Balance at December 31, 2002	103,068,293		$	33,813		$	—	$	(23	)	$	(11,360	)	$	22,430
Repurchase of shares (Note 13(c))	(1,391,500	)		(450	)		—		—			—			(450	)
Settlement of debenture (Note 13(b))	5,206,100			8,399			—		—			—			8,399
Share cancellation costs	—			(1,691	)		—		—			—			(1,691	)

	106,882,893			40,071			—		(23	)		(11,360	)		28,688

Comprehensive loss:
Net loss	—			—			—		—			(4,947	)		(4,947	)
Foreign currency translation loss	—			—			—		(72	)		—			(72	)

Total comprehensive loss	—			—			—		(72	)		(4,947	)		(5,019	)

Balance at December 31, 2003	106,882,893			40,071			—		(95	)		(16,307	)		23,669

Repurchase of shares (Note 13(c))	(340,000	)		(888	)		—		—			—			(888	)
Conversion of convertible debenture (Note13(d))	6,847,215			8,181			—		—			—			8,181
Share cancellation costs	—			(6	)		—		—			—			(6	)
Issuance of share purchase warrants (Note13(f))	—			2,422			—		—			—			2,422
Contributed surplus	—			—			1,374		—			—			1,374

	113,390,108			49,780			1,374		(95	)		(16,307	)		34,752
Net loss	—			—			—		—			(12,776	)		(12,776	)

Balance at December 31, 2004	113,390,108		$	49,780		$	1,374	$	(95	)	$	(29,083	)	$	21,976

The accompanying notes are an integral part of these consolidated financial statements

F-5

Index to Financial Statements

GASTAR EXPLORATION LTD.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY AND COMPREHENSIVE LOSS


	Shares Issued		Common Stock			Additional paid-in capital		Other Comprehensive (loss)			Retained Deficit			Total Shareholders’ Equity
	(in thousands, except share data)
For the Three Months Ended March 31, 2004 and 2005 (Unaudited):

Balance at December 31, 2003	106,882,893		$	40,071		$	—	$	(95	)	$	(16,307	)	$	23,669

Repurchase of shares	(158,800	)		(58	)		—		—			—			(58	)
Conversion of convertible debenture	6,099,999			6,710			—		—			—			6,710
Share cancellation costs	—			(344	)		—		—			—			(344	)

	112,824,092			46,379					(95	)		(16,307	)		29,977
Net loss	—			—			—		—			(670	)		(670	)

Balance at March 31, 2004	112,824,092		$	46,379		$	—	$	(95	)	$	(16,977	)	$	29,307

Balance at December 31, 2004	113,390,108		$	49,780		$	1,374	$	(95	)	$	(29,083	)	$	21,976
Stock options exercised, cash	127,500			24			—		—			—			24
Stock options exercised, non-cash	1,012,500			1,012			—		—			—			1,012
Stock options cancelled in lieu of non-cash exercise	(332,175	)		(1,012	)		—		—			—			(1,012	)
Contributed surplus	—			—			793		—			—			793

	114,197,933			49,804			2,167		(95	)		(29,083	)		22,793
Net loss	—			—			—		—			(7,636	)		(7,636	)

Balance at March 31, 2005	114,197,933		$	49,804		$	2,167	$	(95	)	$	(36,719	)	$	15,157

The accompanying notes are an integral part of these consolidated financial statements

F-6

Index to Financial Statements

Gastar Exploration Ltd.

Consolidated Statements of Cash Flows


	For the Three Months Ended March 31,						For the Years Ended December 31,
	2005			2004			2004			2003			2002
	(unaudited)
	(in thousands)
Cash flows from operating activities:
Net loss	$	(7,636	)	$	(670	)	$	(12,776	)	$	(4,947	)	$	(4,599	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization		2,690			176			3,233			572			360
Impairment of natural gas and oil properties		4,410			—			6,306			552			377
Amortization of deferred lease cost		68			—			33			—			—
Cumulative effect of a change in accounting principle		—			—			—			121			—
Stock compensation expense		793			—			1,374			—			—
Interest and debt related items		447			242			2,291			1,363			1,089
Accretion expense on asset retirement obligation (Note 7)		19			13			52			54			—
Other		(2	)		—			—			—			—
Changes in operating assets and liabilities:
Accounts receivable		(1,493	)		(162	)		(1,494	)		(179	)		166
Prepaid expenses		130			7			(716	)		(45	)		(27	)
Accounts payable and accrued liabilities		947			(268	)		575			62			1,682
Foreign exchange		(1	)		(6	)		(5	)		(80	)		(36	)

Net cash provided by (used in) operating activities		372			(668	)		(1,127	)		(2,527	)		(988	)

Cash flows from investing activities:

Cash call receivable (Note 3)		979			1,220			(5,098	)		(1,220	)		—
Development and purchases of oil and gas properties (Note 4)		(8,266	)		(1,314	)		(16,611	)		(4,763	)		(8,050	)
Sale of oil and gas properties (Note 4)		1			3,000			3,000			8,618			—
Purchase (sale) of furniture, equipment and other		(91	)		—			(2	)		—			4
Site restoration bond purchase (cancellation)		—			—			263			30			(56	)
Foreign exchange		2			—			1			—			(25	)

Net cash provided by (used in) investing activities		(7,375	)		2,906			(18,447	)		2,665			(8,127	)

Cash flows from financing activities:
Repayments of contract payable		—			(688	)		(688	)		—			(1,000	)
Repayment of commitments payable		—			—			(1,342	)		—			—
Repayment of convertible notes payable		—			—			(100	)		—			—
Proceeds from (repayment) of note payable		—			—			—			(630	)		630
Proceeds from issuance of convertible notes payable		—			—			30,000			—			7,481
Proceeds from drilling advances		—			—			—			—			4,010
Proceeds from issuance of senior notes		—			—			25,000			—			—
Proceeds from issuance of subordinated, unsecured notes payable		—			—			3,250			—			—
Accounts payable – joint venture partner		(4,319	)		—			(17,649	)		3,054			—
Debt issue costs		—			—			(2,846	)		—			(693	)
Proceeds from issuance of common shares, net of share issue costs		24			—			—			—			—
Repurchase of common stock		—			(403	)		(894	)		(2,141	)		(1,926	)
Foreign exchange		2			—			—			—			-—

Net cash provided by (used in) financing activities		(4,293	)		(1,091	)		34,731			283			8,502

Increase (decrease) in cash		(11,296	)		1,147			15,157			421			(613	)
Foreign exchange gain on cash held in foreign currency		—			—			4			4			7
Cash, beginning of period		15,842			681			681			256			862

Cash, end of period	$	4,546		$	1,828		$	15,842		$	681		$	256

Cash paid during the period for:
Interest	$	898		$	383		$	600		$	1,272		$	772
Income taxes	$	—		$	—		$	—		$	—		$	—

The accompanying notes are an integral part of these consolidated financial statements

F-7

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Business and Basis of Presentation

These consolidated financial statements represent the consolidated statements for First Sourcenergy Wyoming, Inc. (“FSW”) since February 29, 2000, the date it commenced operations. During 2000, FSW completed a reverse takeover (“RTO”) of CopperQuest Inc and this transaction was accounted for as a recapitalization of FSW. Effective May 16, 2000, CopperQuest Inc. changed its name to Gastar Exploration Ltd. (“the Company” or “Gastar”).

The Company’s principal business activities include the selection, acquisition, exploration and development of oil and gas properties. The Company continues to incur losses and has significant cash flow requirements in order to continue the process of exploring and developing its oil and gas properties.

The Company and a significant shareholder of the Company, Geostar Corporation (“Geostar” for the corporation and its subsidiaries), are partners to a signed Participation and Operating Agreement (“POA”). Pursuant to the terms of this POA, Geostar acquires in arms-length transactions properties from various third parties on behalf of itself and Gastar. Following successful due diligence, Gastar has the right to participate in up to a 75% interest in any Geostar properties that may be acquired under this POA on an “at cost” basis. As detailed in Note 16(b) Geostar has also provided a convertible debenture to the Company with the intent to provide up to CDN $25 million in funds for continued operations and to help develop the Company’s oil and gas properties. Advances under the debenture were subject to Geostar’s availability of funds and the approval of the requested advances by Geostar’s board of directors. The funds advanced under the convertible debenture were repayable by Gastar either in cash or in shares, at prevailing market prices, at the option of the Company.

Subsequent to year end, effective January 1, 2005, Geostar and the Company terminated the convertible debenture arrangement and commenced operating the East Texas properties under a Joint Operating Agreement (“JOA”) which has standard industry terms for the operator (Geostar) (Note 16(c). Under the new arrangement, the Company will be required to find financing for its share of future joint venture costs.

2. Significant Accounting Policies

The consolidated financial statements of the Company (in United States (“US”) dollars unless otherwise noted) have been prepared by management in accordance with generally accepted accounting principles (“GAAP”) in the United States. The preparation of consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The consolidated financial statements have, in management’s opinion, been properly prepared using careful judgment with reasonable limits of materiality and within the framework of the significant accounting policies summarized below:

(a) Consolidation

The consolidated financial statements include the accounts of the Company and the consolidated accounts of all its subsidiaries. The entities included in these consolidated accounts are 100% owned unless specified: New Energy West Corporation (“NEC”); 616694 Alberta Ltd.; Monterey Resources, Inc.; New Energy West (U.S.A.) Corporation; 1075191 Ontario Ltd., (“OntarioCo”); First Sourcenergy Wyoming, Inc. (“FSW”); First Source Development, Inc. (“FSD”); First Texas Development, Inc. (“FTD”); First Source Gas LP; Bossier Basin LLC; First Sourcenergy Group, Inc. (“FSG”); First Sourcenergy Kansas, Inc. (“FSK”); First Sourcenergy Victoria, Inc. (“FSV”); Squaw Creek, Inc. (“SCI”); First Appalachian Development, Inc. (“FAD”) and Oil and Gas Services Inc. (“OGS”). All significant intercompany accounts and transactions have been eliminated.

F-8

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(b) Furniture, Equipment and Other

Furniture, equipment and other are carried at historical cost and are amortized over various periods ranging from three to seven years on a straight-line basis.

The Company follows the full cost method of accounting for oil and gas operations pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (“SFAS No. 19”) whereby all costs of exploring for and developing oil and natural gas reserves are initially capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities.

Reserves, future production profiles, and net cash flows are estimated by an independent professional reservoir engineering firm. While Gastar has hired a qualified reservoir engineering firm, their estimates are inherently uncertain, involve numerous assumptions that may not be realized, and predict asset values that may not be indicative of the true market value of the assets evaluated. As a result of the inherent uncertainties and changing technical and economic assumptions, reserve estimates are subject to revisions that can materially impact Company results.

In applying the full cost method, the Company performs a ceiling test on properties which compares the net cost of oil and gas properties (“net cost”), which is equal to the unamortized cost of oil and gas properties less any deferred income taxes related to those properties with the calculated ceiling. The calculated ceiling (“ceiling”) is equal to the sum of the estimated discounted future net revenues from production of proved reserves as determined by an independent engineer, generally using prices in effect at the end of the period held flat for the life of production excluding the estimated abandonment cost for properties with asset retirement obligations recorded on the balance sheet and including the effect of derivative contracts that qualify as cash flow hedges, discounted at 10%, the lower of cost or estimated fair value of unproved properties included in the costs being amortized and the cost of properties not being amortized less the income tax effects. If the net cost exceeds the ceiling, an impairment loss will be determined. The impairment loss is measured as the amount by which the net cost exceeds the ceiling and is shown as a reduction in oil and gas properties and as additional depletion. Proceeds from a sale of oil and natural gas properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion or amortization.

(d) Mineral resource properties

All acquisition, exploration and related direct and indirect overhead expenditures are capitalized. The costs relating to a property abandoned are written off when the decision to abandon is made.

F-9

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(e) Site restoration bond

The site restoration bond is a drilling security bond with the Minister of Mineral Resources in Australia for future site restoration on Petroleum Exploration License 238 (“PEL 238”). The bond was refunded in 2004 as the Company is no longer the operator. The current operator has replaced the bond with the Minister of Mineral Resources.

(f) Revenue recognition

Revenue is recognized on delivery to customers pursuant to the sales method net of royalties.

(g) Financial instruments

The Company carries various forms of financial instruments. Unless otherwise indicated, it is management’s opinion that the Company is not exposed to significant interest, currency or credit risks arising from these financial instruments. The fair values of these financial instruments approximate their carrying values, unless otherwise noted.

(h) Foreign exchange

Foreign currency balances of the parent company and non-monetary assets and liabilities are translated at the rates of exchange on the particular transaction date. Monetary assets and liabilities denominated in foreign currencies that remain outstanding at the balance sheet date are translated at period end exchange rates with resulting gains (losses) being recognized in the period. The accounts of all active subsidiaries are maintained in US dollars.

(i) Deferred income taxes

The liability method of tax allocations is used, based on differences between financial reporting and tax bases of assets and liabilities. No future tax asset has been recorded as it is uncertain whether the Company will be able to realize this benefit.

(j) Reporting currency

Majority of the Company’s operations are conducted by its US subsidiaries in US dollars. The operations outside of the US are primarily oil and gas property development in Australia which are conducted in Australian dollars (“AUD”). Limited operations are conducted in Canadian dollars. The Company reports its operations in US dollars, its functional currency.

(k) Treasury stock method

Basic earnings per common share is computed by dividing earnings by the weighted average number of common shares outstanding for the period. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments.

F-10

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(l) Cash and cash equivalents

Cash and cash equivalents include short-term investments, such as money market deposits or highly liquid debt instruments, with a maturity of three months or less when purchased. We maintain our cash in bank deposit accounts, which, at times, may exceed federally insured limits. We have not experienced any losses in such accounts and believe we are not exposed to any significant risk of loss.

(m) Stock-based compensation

The Company reports compensation expense for stock options granted to employees, officers and directors using the fair value method. Fair values are determined using the Black-Scholes model. Compensation costs are recorded over the vesting period.

Effective January 1, 2003, the Company adopted SFAS No. 123 which requires the Company to provide pro-forma information regarding net income as if the compensation costs for the Company’s stock option plan had been determined in accordance with the fair value based method prescribed in SFAS No. 123. To provide the required pro-forma information, the Company estimates the fair value of each stock option at the grant date by using the Black-Scholes option-pricing model.

The range of fair values of the Company’s stock options granted was CDN $0.58-$1.77 in 2004 and CDN $0.55 - $1.10 in 2002. The fair values were determined by using the Black-Scholes option model with the following weighted average assumptions for all periods: expected dividend yield 0%, expected volatility 30% - 55%, risk free interest rate 5% and expected option term of four years.

The table below reflects the pro-forma impact of stock-based compensation on the Company’s net loss and loss per share had the Company applied SFAS No, 123:


	For the Three Months Ended March 31,						For the Years Ended December 31,
	2005			2004			2004			2003			2002
	(unaudited)
	(in thousands except share and per share data)
Net loss – US GAAP, as reported	$	(7,636	)	$	(670	)	$	(12,776	)	$	(4,947	)	$	(4,599	)
Cost of Compensation expense using fair value		(270	)		(678	)		(1,883	)		(3,743	)		(6,968	)

Net loss – US GAAP, pro forma	$	(7,906	)	$	(1,348	)	$	(14,659	)	$	(8,690	)	$	(11,567	)
Loss per share – US GAAP, as reported	$	(0.067	)	$	(0.006	)	$	(0.115	)	$	(0.047	)	$	(0.047	)
Loss per share – US GAAP, pro forma	$	(0.069	)	$	(0.013	)	$	(0.132	)	$	(0.083	)	$	(0.117	)

(n) Deferred financing costs

Deferred financing costs include expenses of debt financings undertaken by the Company including commissions, legal fees, value attributed to warrants issued in conjunction with the financing and other direct costs of the financing. Using the interest method, the deferred financing costs are amortized over the term of the related debt.

(o) Accretion on convertible notes

Using the interest method, the equity component of the convertible notes are amortized over the term of the related debt.

F-11

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(p) Asset retirement obligation

Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”) using a cumulative effect approach to recognize transition amounts for asset retirement obligations, asset retirement costs and accumulated depreciation. Asset retirement costs and liabilities associated with site restoration and abandonment of tangible long-lived assets are initially measured at a fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash flows. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost are recognized in the results of operations. Upon adoption, the Company recorded a cumulative-effect-type adjustment for an increase to loss of $121,000 net of deferred taxes of $nil. Additionally, the Company established an asset retirement obligation of $769,000, an increase to property and equipment of $667,000 and an increase to accumulated DD&A of $19,000.

The schedule below reflects, on a pro forma basis, the net loss, net loss per share amounts and the liability for asset retirement obligations as if SFAS No. 143 had been applied during all the periods presented.


	For the Years Ended December 31,
	2003			2002
	(in thousands, except per share data)
Net loss, as reported	$	(4,947	)	$	(4,599	)

Plus cumulative effect of change in accounting principle		121			—
Net change in depletion, depreciation and amortization of property and equipment due to adoption of SFAS No. 143		—			(20	)
Less accretion of asset retirement obligation		—			(63	)
Deferred taxes		—			—

Effect on net loss		121			(83	)

Net loss, as adjusted	$	(4,826	)	$	(4,682	)

Basic earnings per share:
Net loss per share, as reported	$	(0.047	)	$	(0.047	)
Effect on net loss		0.001			(0.001	)

Net loss, as adjusted	$	(0.046	)	$	(0.048	)


	As of December 31, 2002 As reported			Adjustments			As of December 31, 2002 as restated
	(in thousands)
Oil and gas properties	$	34,457		$	648		$	35,105
Asset retirement obligation	$	(77	)	$	(769	)	$	(846	)

(q) Joint venture operations

The majority of the Company’s petroleum and natural gas exploration activities are conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities.

F-12

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(r) Reclassification

Certain information provided for the prior year has been reclassified to conform to the presentation adopted in 2005.

(s) Goodwill

On January 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”). Under SFAS No. 142, goodwill and indefinite-lived intangible assets are no longer amortized but are reviewed annually (or more frequently if impairment indicators arise) for impairment. Separable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives (but with no maximum life). The Company has no goodwill, so adoption of this standard had no impact on our financial position or results of operations.

(t) Unaudited Periods

The financial information with respect to the three months ended March 31, 2005 and 2004 is unaudited. In the opinion of management, this information contains all adjustments, consisting only of normal recurring accruals, necessary for a fair presentation of the results for the periods presented. The results of operations for interim periods are not necessarily indicative of the results of operations for the full fiscal years.

(u) Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development and production of natural gas and crude oil. The Company’s operational activities are conducted in the United States and Australia with only the United States currently having revenue generating operating results. The identifiable assets for each country have been disclosed in Note 4 .

(v) New accounting policies

In December of 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS 123R “Share Based Payments” which addresses the accounting for transactions in which an entity exchanges its equity instruments for goods and services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. This statement is a revision of FASB statement SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”). This statement supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees”. Among other things, this statement requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. That cost is recognized over the period during which an employee is required to provide service in exchange for the award – the requisite service period (usually the vesting period). This statement is to be applied as of the beginning of the first interim or annual period that begins after June 15, 2005, but earlier adoption is encouraged. Because we have disclosed pro-forma fair based value amounts in accordance with the original SFAS No. 123, it allows a company to adopt using a modified prospective approach. This will require the Company to recognize in the third quarter of 2005, compensation expense for options granted after June 15, 2005 and compensation expense for awards not yet vested but still outstanding.

In December of 2004, FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets – An Amendment of APB Opinion No. 29” (“SFAS No. 153”). The guidance in APB Opinion No. 29,

F-13

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

“Accounting for Nonmonetary Transactions” (“APB Opinion No. 29”) is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB Opinion No. 29, however, included certain exceptions to that principle. This Statement amends APB Opinion No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Earlier application is permitted for nonmonetary asset exchanges occurring in fiscal periods beginning after the date this Statement is issued. The provisions of this Statement shall be applied prospectively. The adoption of SFAS No. 153 did not have any impact on the Company’s financial statements.

3. Cash Call Receivable


	Opening balance		Cash Call Advances		Amounts Spent		Cash Calls, ending
	(in thousands)
Lone Oak Ranch #1 well	$	2,344	$	—	$	2,068	$	276
Greer #1 well		3,974		1,460		3,687		1,747
Fridkin Kaufman #2 well		—		5,680		2,364		3,316

Balance as of March 31, 2005	$	6,318	$	7,140	$	8,119	$	5,339

Fridkin Kaufman #1 well	$	1,220	$	—	$	1,220	$	—
Cheney #1 well		—		9,015		9,015		—
Lone Oak Ranch #1 well		—		8,397		6,053		2,344
Greer #1 well		—		4,122		148		3,974

Balance as of December 31, 2004	$	1,220	$	21,534	$	16,436	$	6,318

Fridkin Kaufman #1 well	$	—	$	5,310	$	4,090	$	1,220

Balance as of December 31, 2003	$	—	$	5,310	$	4,090	$	1,220

All cash calls are paid to the operator, Geostar (Note 1). Geostar invoices the Company for their proportionate share of planned authorized expenditures upon Company execution of the final drilling AFE.

F-14

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

4. Property and Equipment

The amount capitalized as oil and gas properties was incurred for the purchase and development of various properties in the states of California, Montana, Texas, West Virginia and Wyoming in the US and in New South Wales and Victoria in Australia.

The following schedule represents natural gas and oil property costs by country:


	US			Australia			Total
	(in thousands)
From inception to March 31, 2005:
Cost	$	81,410		$	2,863		$	84,273
Asset retirement		1,673			80			1,753
Impairment of natural gas and oil properties		(15,126	)		(604	)		(15,730	)
Accumulated depletion		(6,933	)		—			(6,933	)

Net book value at March 31, 2005		61,024			2,339			63,363
Furniture, equipment and other, net		89			7			96

Total property and equipment, net	$	61,113		$	2,346		$	63,459

From inception to December 31, 2004:
Cost	$	67,991		$	2,629		$	70,620
Asset retirement		1,423			79			1,502
Impairment of natural gas and oil properties		(10,716	)		(604	)		(11,320	)
Accumulated depletion		(4,246	)		—			(4,246	)

Net book value at December 31, 2004		54,452			2,104			56,556
Furniture, equipment and other, net		—			8			8

Total property and equipment, net	$	54,452		$	2,112		$	56,564

From inception to December 31, 2003:
Cost	$	35,274		$	5,719		$	40,993
Asset retirement		743			85			828
Impairment of natural gas and oil properties		(4,411	)		(604	)		(5,015	)
Accumulated depletion		(1,015	)		—			(1,015	)

Net book value at December 31, 2003		30,591			5,200			35,791
Furniture, equipment and other, net		—			8			8

Total property and equipment, net	$	30,591		$	5,208		$	35,799

Excluded from the depletion base are unproved property costs of $36.6 million at March 31, 2005, $29.8 at December 31, 2004 and $26.9 million at December 31, 2003, which consists primarily of drilling in progress costs of approximately $18.0 million at March 31, 2005, $12.9 million at December 31, 2004 and $9.8 million at December 31, 2003 and acreage acquisition costs of approximately $18.6 million at March 31, 2005, $16.9 million at December 31, 2004 and $17.1 million at December 31, 2003.

At March 31, 2005 and December 31, 2004, the results of management’s ceiling test evaluation resulted in a write down for the US properties of $4.4 million and $6.3 million (2003 - $451,000). Management also determined that there was no impairment in the carrying values of the Australian properties at March 31, 2005 and December 31, 2004 (2003-$100,000).

F-15

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Of the total expenditures incurred on oil and gas properties in the first quarter of 2005 in the amount of $14.7 million, $6.4 million were incurred pursuant to the terms of the JOA with Geostar. Oil and gas properties were reduced by $1.0 million upon reclassification of drilling advances and $1,000 upon sale of acreage.

Of the total expenditures incurred on oil and gas properties during 2004 in the amount of $34.9 million (2003 - $11.3 million), $17.7 million (2003 - $5.2 million) were financed through the convertible debenture with Geostar. Proceeds from the sale of assets were $3.0 million (2003 - $8.6 million) and were credited to oil and gas properties. Oil and gas properties were reduced by $2.0 million (2003 - $1.0 million) upon reclassification of drilling advances and adjusted by $313,000 (2003- $ nil) for a settlement (Note 6).

Included in oil and gas properties are direct travel and supplies expenses capitalized in the amount of $Nil for the three months ended March 31, 2005, $6,000 for December 31, 2004 (2003 - $Nil).

In 2003, the Company entered into a farm-in agreement pursuant to the terms of which the Company received $3.0 million in 2004 for 30% of its PEL 238 CBM rights. The joint venture partners may earn an additional 35% by spending up to AUD $7.0 million of development costs. At December 31, 2004, the joint venture partners had earned an additional 20% (i.e. a total 50% working interest) by spending an additional AUD $4.0 million.

The Company also has a 75% working interest in the CBM and Mineral Sands rights in EL 4416 in the Gippsland Basin, Victoria, Australia property.

Pursuant to the terms of the Earn-In Joint Venture agreement with a third party, the Company’s interest in the Powder River Basin properties was reduced by 66%. The Company received approximately $6.9 million in 2003 in conjunction with the joint venture agreement. The Company has an overriding royalty interest in an additional 2,400 net acres in the Culp Draw and Table Mountain area of the Powder River Basin pursuant to the sale of its interest for approximately $1.7 million in cash in 2003.

The Company has, pursuant to the terms of an agreement executed in 2003 with an unrelated third party industry participant, earned a 56.25% working interest in the Company’s East Texas properties. The third party retained a right to a 25% back in after payout interest in the Lone Oak Ranch #1 well, drilled per the terms of a third party agreement.

F-16

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

5. Deferred Charges


	Cost			Accumulated Amortization			Net Book Value
	(in thousands)
Deferred Financing Costs
Balance as of December 31, 2002	$	1,119		$	(270	)	$	849
Additions in the year		—			(449	)		(449	)

Balance as of December 31, 2003		1,119			(719	)		400
Additions in the year:
Value assigned to warrants issued (Note a)		358			(218	)		140
Cash commissions and other related expenses paid (Notes 8,10, and 11)		2,846			(215	)		2,631

Balance as of December 31, 2004		4,323			(1,152	)		3,171
Amortization for the period		—			(287	)		(287	)

Balance as of March 31, 2005	$	4,323		$	(1,439	)	$	2,884

Deferred Lease Costs

Additions 2004 – Gas treating agreements	$	542
Amortization expense		(33	)
Reclass to current portion		(238	)

Balance – December 31, 2004	$	271

Balance – December 31, 2004, net	$	509
Amortization expense		(68	)
Reclass to current portion		(170	)

Balance – March 31, 2005	$	271

Total Deferred Charges – March 31, 2005	$	3,155

Total Deferred Charges – December 31, 2004	$	3,442

Total Deferred Charges – December 31, 2003	$	400

(a)

In 2004, the Company issued 2,992,261 warrants expiring at varying dates commencing from October 13, 2007 to November 20, 2009 (Note 13(e)) with exercise prices ranging from $2.76 to $3.87 (CDN $3.64 to $4.65) per share in conjunction with financings completed in the year. The fair value of these warrants was estimated to be $2.4 million, of which $359,000 was deferred and is being amortized over the term of the related debt and $2.1 million was netted against the respective debt. The amortization period ranges from 3 to 5 years.

All of the above warrants were valued using the Black-Scholes option pricing model based on the following assumptions: dividend yield - nil; expected volatility – ranging from 30% to 40%; risk free interest rate – 5%; term 3 to 5 years.

(b)

In 2004, FTD and First Source Texas, Inc. (“FST”), a wholly owned subsidiary of Geostar, entered into Gas Treating Agreements with a third party for the Fridkin-Kaufman #1 (“F-K #1”) and Cheney #1 wells. The primary term of the agreements are 2 years beginning on the first day of the month immediately following the month during which the plant becomes operational. The Company’s portion of costs relating to equipment leases and operations of the plants over the two year period are estimated to approximate $1.1 million. The Company has recorded an estimated $465,000 for its portion of installation and transportation

F-17

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

costs for the plants and has also recorded an accrued liability for an estimated $77,000 for its portion of costs relating to the demobilization of the plants. These costs are being amortized to lease operating expense over the term of the related agreement.

6. Contract Payable

Pursuant to the acquisition of certain properties in Australia, the Company was obligated to pay $2.0 million, due in two installments. In August 2002, the first installment of $1.0 million was paid on the contract payable pursuant to the acquisition of PEL 238 interests in New South Wales, Australia from an unrelated third party and the second installment of $1.0 million was due in February 2004. The second payment was reduced to $688,000 per a settlement agreement in 2004 (Note 18 (c)) and was paid in the first quarter of 2004.

7. Asset Retirement Obligation

Effective January 1, 2003, the Company changed its policy on accounting for liabilities associated with site restoration and abandonment of its oil and gas properties pursuant to SFAS No. 143. The undiscounted amount of expected cash flows required to settle the asset retirement obligations is estimated at $2.5 million (December 31, 2004 - $2.5 million and December 31, 2003 - $1.5 million). Of these payments, 89% are expected to be made over the next 5 years, 9% is expected to be made in years 6-10, with the remainder being paid in years 11-19. The liability for the expected cash flows, as reflected in the consolidated financial statements, has been discounted at 6.8% (2003 - 7.34%).


	As of March 31, 2005		As of December 31,
	As of March 31, 2005		2004			2003
	(unaudited)
	(in thousands)
Asset retirement obligation, beginning of year	$	1,711	$	984		$	846
Liabilities incurred		250		166			174
Accretion expense		19		52			54
Reduction due to sale of working interest		—		(57	)		(347	)
Revision in estimated cash flows		—		566			257

Asset retirement obligation, end of year	$	1,980	$	1,711		$	984

8. Convertible Notes

In 2002 the Company issued unsecured 12%, 2 year Convertible Notes, (“Convertible Notes”) in two offerings totaling $8.3 million. The first offering ($6.7 million) was convertible at $1.10 per share and the second ($1.6 million) at $1.97 per share. The Convertible Notes outstanding was represented by:


	As of December 31, 2004
	(in thousands)
Current portion	$	1,552
Long term		6,562
Unamortized debt discount		167

	$	8,281

F-18

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In 2004, Convertible Notes totaling $8.2 million were converted and the Company issued the noteholders a total of 6,847,215 common shares (Note 13). Convertible Notes in the amount of $100,000 were not converted and were subsequently paid in the fourth quarter. The equity portion of these Convertible Notes in the amount of $1.8 million was reclassed to share capital upon conversion.

On November 16, 2004, the Company announced that it had closed a $30.0 million issuance of Convertible Senior Unsecured Debentures (“Convertible Senior Debentures”). The Convertible Senior Debentures have a term of 5 years and will be due November 20, 2009 and bear interest at 9.75% per annum, payable quarterly. The Convertible Senior Debentures are convertible by the holders into common shares at a conversion price of $4.38 (CDN $5.45) per share. The debentures may be redeemed by the Company in the event that the Liquidity Event (defined as the Company receiving a no-action letter from the SEC regarding the shares to be issued upon conversion, the Company’s pending U.S. Registration Statement being declared effective or the delivery of an opinion of Company’s counsel that the shares to be issued upon conversion are freely tradable) has not occurred on or prior to (i) March 10, 2005, the conversion price shall be automatically adjusted to equal $4.54, (ii) May 10, 2005, the conversion price shall be automatically adjusted to equal $4.46, and (iii) July 10, 2005, the conversion price shall be automatically adjusted to equal $4.38. Additionally, the Convertible Senior Debentures will be redeemable by the Company at any time after November 13, 2006 at a redemption price equal to par plus accrued and unpaid interest; provided that the volume weighted average trading price of the common shares of the Company, for at least 20 trading days in any consecutive 30 day period, exceeds $6.03 (CDN $7.50).

Convertible Senior Debenture Financing related costs paid to unrelated parties amounted to $1.9 million. These costs have been deferred and are being amortized over the life of the debentures. The Company also issued 259,740 broker warrants with an exercise price of $3.87 (CDN $4.65) (Note 13 (e)).

There was no beneficial conversion feature associated with the Convertible Senior Debentures.

9. Drilling Advances Liability

In 2002 the Company pre-sold working interests, to arms length third parties, in four wells and raised $4.0 million in financing for a planned drilling program on the Company’s East Texas natural gas assets. Share purchase warrants were also issued to subscribers on a pro-rata basis, with each warrant having a three year term entitling the holder to acquire one common share of Gastar at a price of $1.49 (CDN $2.35) per share. A total of 2,005,027 warrants were issued on September 23, 2002 and expire on September 23, 2005. The Company paid to the working interest owners an advance on production revenue equal to 10% per annum of the amount invested on a quarterly basis for the first 12 months of the investment (herein referred to as “interest advances”). These have been recorded as interest expense. These payments will be deducted against future working interest revenue earned by the working interest owners.

The $4.0 million was classified as a “drilling advances liability” with 25% being credited to oil and gas properties when the wells were drilled. At December 31, 2003 three wells remained to be drilled. Two were drilled in 2004 and the remaining well was drilled in the first quarter of 2005.

10. Subordinated, Unsecured Notes Payable

In 2004, the Company completed a $3.25 million subordinated, unsecured note financing (“Unsecured Notes”). The Unsecured Notes mature between April and September 2009 and bear interest at 10% per annum and are callable by the Company after 2 years at 108% of the principal amount. The call premium reduces to

F-19

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

105% after three years and 101% after four years. The subscribers were issued 232,521 warrants exercisable at prices ranging from $2.76 to $3.03 (CDN $3.64 to $4.18) expiring at varying dates between April and September 2009. The value of the warrants ($235,000) (Note 13(e)) was deducted against the debt. Interest expense relating to the amortization of the warrants of $12,000 was recorded for the first quarter of 2005 (2004 - $24,000). Cash commissions of $196,000 were incurred, which have been capitalized and will be amortized over the term of the subordinated, unsecured notes.

11. Senior Notes

In June 2004, a wholly-owned subsidiary of the Company issued $15.0 million of unsecured senior notes (“Senior Notes”) to a private investment company. The Senior Notes mature on July 1, 2009 and bear an annual interest rate of 15% payable semi-annually with a Company option to pay interest due before December 31, 2005 in-kind through the issuance of additional Senior Notes. The Senior Notes are callable at any time by the Company at a call premium of 104% (decreasing ½% every six months) of the principal outstanding. Warrants representing in value 10% of the principal balance were issued in conjunction with the Senior Notes. The warrants are exercisable into an aggregate of 510,525 common shares of the Company upon payment of an exercise price of $3.23 (CDN $4.40) per common share on or before five years from date of issuance. The Company has reserved the common shares to be issued upon exercise of these warrants.

As part of the financing, the Senior Note subscriber additionally received a 2% overriding royalty interest (“ORRI”) in the F-K #1, Cheney #1, and two future deep wells in which Gastar participates in the East Texas Bossier project area. Gastar has a right of first refusal on any sale of the ORRI granted to the subscriber of the Senior Notes.

In October 2004, the wholly-owned subsidiary of the Company issued an additional $10.0 million of Senior Notes to the same private investment company on the same terms and conditions as the June 2004 Senior Notes. In conjunction with the additional Senior Note issuance, the maturity of all Senior Notes and warrants expiry was amended from five years to three years. Thus all Senior Notes mature and related warrants expire on October 13, 2007. With the October 2004 Senior Note issuance, additional warrants exercisable into an aggregate of 1,989,475 common shares of the Company upon payment of an exercise price of $3.63 (CDN $4.54) were issued. The Company has reserved the common shares to be issued upon exercise of these warrants.

As part of the October 2004 Senior Note issuance, the subscriber received a small proportionate ORRI in one future deep Hilltop Bossier well in which Gastar participates in the East Texas Bossier project area. Gastar has a right of first refusal on any sale of the ORRI granted to the subscriber of the Notes.

Interest payable in 2004 in the amount of $1.5 million was paid in-kind via the issuance of additional Senior Notes. This additional note bears the same terms as the related Senior Notes. No additional warrants are issuable on these interest payable notes. The value of the warrants ($1.8 million) Note 13(e) was deducted from the debt. Interest expense relating to the amortization of the warrants of $149,000 for the first quarter of 2005 and $184,000 for year end 2004 was also recorded.

Total commissions and other direct costs of $750,000 were incurred and will be amortized over the life of the Senior Notes.

F-20

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

12. Interest Expense

The following table summarizes interest expense components:


	For the Three Months Ended March 31,				For the Years Ended December 31,
	2005		2004		2004		2003		2002
	(unaudited)
	(in thousands)
Cash and accrued	$	1,706	$	177	$	957	$	1,204	$	954
Paid in-kind		—		—		1,483		—		—
Deferred financing cost amortization		447		242		808		1,363		1,089

Total	$	2,153	$	419	$	3,248	$	2,567	$	2,043

13. Common Stock

(a) Authorized

Unlimited number of common shares without par value.

(b)

In 2003, at various times during the year, the Company exercised its option under the Convertible Debenture Agreement with Geostar (Note 1) to issue shares of Gastar in full payment of amounts owed to Geostar. A total of 5,206,100 shares were issued at market prices ranging from $1.56 (CDN$2.10) to $1.95 (CDN$2.52).

(c)

The Company conducted normal course issuer bids at various times in 2004 and 2003. Pursuant to this program, the Company repurchased 340,000 (2003 – 1,391,500) common shares for a total amount of $888,000 (2003 - $2.1 million). The bid expired on August 4, 2004.

(d)

As detailed in Note 8, during 2004 a principal amount of $8.2 million in 12% convertible debentures and notes were converted into an aggregate of 6,847,215 shares of Company common stock. Of the shares issued 6,099,999 shares were at a conversion price of $1.10 and 747,216 shares were at a conversion price of $1.97 per share.

(e)

The following table summarizes warrant information to purchase common shares:


	Number of Warrants	Value of Warrants (in thousands)		Warrant Price per Share Range in CDN$	Warrant Price per Share Range in USD$	WA⁽¹⁾ Remaining Life in Years	WA⁽¹⁾ Exercise Price in CDN$	WA⁽¹⁾ Exercise Price in USD$
Warrants outstanding December 31, 2002 and 2003	2,005,027	$	425	2.35	1.49	0.50	2.35	1.49
Issued in conjunction with:
Senior Notes (Notes 11 and 18(n))	2,500,000		1,828	4.40 - 4.54	3.23 - 3.63	2.50	4.51	3.55
Unsecured Notes (Note 10)	232,521		235	3.64 - 4.18	2.76 - 3.03	4.11	3.76	2.80
Convertible Notes (Note 8)	259,740		359	4.65	3.87	4.67	4.65	3.87

Warrants outstanding December 31, 2004 and March 31, 2005	4,997,288	$	2,847	2.35 - 4.65	1.49 - 3.87	1.89	3.62	2.70

F-21

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

⁽¹⁾	WA – weighted average

(f)

At March 31, 2005, the Company has reserved 35,075,203 shares to be issued pursuant to the conversion of convertible debt up to (6,849,315), exercise of options (23,228,600), and the exercise of warrants (4,997,288).

14. Stock-Based Compensation

The Company has a stock-based compensation plan that allows employees to purchase common shares of the Company. Option exercise prices approximate the market price for the common shares on the date the options were issued. Options granted under the plan are generally fully exercisable after four years and expire five years after the grant date. The Company can issue up to 25% of the issued and outstanding shares under this plan.

The Company recorded $793,000 in stock-based compensation expense for stock options granted to employees and directors in the first quarter of 2005 and $1.4 million for the year 2004 using the fair-value method with the following assumptions: volatility – 30% to 55%; risk-free interest rate – 5%; and expected life of 4 years. The 5,470,000 options issued in 2004 had a fair value on grant date ranging from $0.47 to $1.42 per option.

The following is a summary of options to purchase common shares outstanding:


	Number of Options		Option Price per Share Range in CDN$	Option Price per Share Range in USD$	WA⁽¹⁾ Remaining Life in Years	WA⁽¹⁾ Exercise Price in CDN$	WA⁽¹⁾ Exercise Price in USD$
Options outstanding, December 31, 2002 and 2003	18,898,600		0.30 - 2.81	0.19 - 1.79	—	1.92	1.20

Options issued, April 20, 2004	825,000		3.70	2.75	—	3.70	2.75

Options issued, August 4, 2004	4,645,000		3.41	2.59	—	3.41	2.59

Options outstanding, December 31, 2004	24,368,600		0.30 - 3.70	0.19 - 2.75	—	2.26	1.52

Options exercised 2005:

February 4 to March 14, 2005	(240,000	)	0.30	0.19	—	0.30	0.19

February 9, 2005	(700,000	)	0.30 - 2.76	0.19 - 1.74	—	1.35	0.85

March 2, 2005	(200,000	)	1.66	1.09	—	1.66	1.09

Options outstanding, March 31, 2005	23,228,600		0.30 - 3.70	0.19 - 2.75	1.71 years	2.30	1.55

⁽¹⁾	WA – weighted average

In 2005, 1,140,000 stock options were exercised with exercise prices ranging from $0.19—$1.74 (CDN $0.30—$2.76). A portion of the stock options exercised were on a non-cash basis. The Company issued a total of 807,825 shares and 332,175 shares reserved for stock option exercise were cancelled. Shares related to the options exercised in March were issued in April 2005.

F-22

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Of the total options outstanding, 14,533,700 options have vested as of March 31, 2005 which have a weighted average exercise price of $1.10 and a weighted average life of .83 years. The expiry dates for the issued 23,228,600 options outstanding are as detailed below:


Number of Options	Option Price per Share Range in CDN$	Option Price per Share Range in USD$	Expiry date
5,971,500	0.30	0.19	May 31, 2005
—	1.66	1.09	July 9, 2005
11,087,100	2.76	1.74	July 13, 2006
700,000	2.81	1.79	April 26, 2007
825,000	3.70	2.75	April 20, 2009
4,645,000	3.41	2.59	August 4, 2009

23,228,600	0.30 - 3.70	0.19 - 2.75

15. Loss per share

In accordance with the provisions of SFAS No. 128, “Earnings per Share” (“SFAS No. 128”), basic earnings per share is computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted earnings per share is computed based upon the weighted-average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities. Diluted amounts are not shown below as such would be anti-dilutive.


	For the Three Months Ended March 31,						For the Years Ended December 31,
	2005			2004			2004			2003			2002
	(unaudited)
	(in thousands)
Basic loss per share:
Numerator
Net loss before cumulative effect of change in accounting principle	$	(7,636	)	$	(670	)	$	(12,776	)	$	(4,826	)	$	(4,599	)
Net loss	$	(7,636	)	$	(670	)	$	(12,776	)	$	(4,947	)	$	(4,599	)

Denominator
Common shares outstanding		113,788,198			107,265,493			111,374,446			104,958,180			98,617,920

Basic loss per share:
Net loss per share before cumulative effect of change in accounting principle	$	(0.067	)	$	(0.006	)	$	(0.115	)	$	(0.046	)	$	(0.047	)
Net loss per share applicable to all common shares	$	(0.067	)	$	(0.006	)	$	(0.115	)	$	(0.047	)	$	(0.047	)

16. Related Party Transactions

Except as disclosed elsewhere in these financial statements, the Company had the following related party transactions:

(a)

In 2001, the Company entered into a POA with Geostar. For the East Texas properties, the POA was replaced effective January 1, 2005 with a Joint Operating Agreement (“JOA”) as detailed in Note 16(c)

F-23

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

below. Pursuant to the terms of the original POA, which still governs the Company’s West Virginia and certain of our Australian assets, the Company has the option to participate as a working interest partner in properties in which Geostar and its subsidiaries have interests in on an “at cost” basis, subject to Gastar’s full due diligence review prior to its participation election. Upon agreeing to participate, the Company is responsible for its proportionate share of actual costs expended by Geostar and its subsidiaries to third parties on an “at cost” basis. The balance of $601,000 at December 31, 2004 and $39,000 at December 31, 2003, represented amounts owed to Geostar and its subsidiaries for natural gas and oil property development. The 2003 balance was settled in 2004 by cash payment.

(b)

On June 1, 2000, the Company entered into an agreement with Geostar, a significant shareholder, to settle accounts payable related to the development of natural gas and oil properties with the issuance of a floating convertible debenture for up to CDN$25.0 million. Under the agreement, Geostar would continue to provide funds for development and operations by allowing the Company to draw down on the debenture. Advances under the debenture were subject to Geostar’s availability of funds and the approval of the requested advances by Geostar’s board of directors. The debenture was payable in cash or convertible into common shares, at prevailing market prices at the option of the Company.

(c)

Effective January 1, 2005, the Company and Geostar entered into a JOA covering an Area of Mutual Interest (“AMI”) in East Texas, with Gastar as non operator and Geostar as operator. Under the terms of the JOA, Geostar receives overhead reimbursement equal to 12.5% of development costs for the first 10 wells drilled after the effective date, 10% of the development costs for the 11^th through 20^th wells and 8.5% of the developments costs for all subsequent wells. As a result, Geostar no longer charges Gastar a proportionate amount of direct salary and shared premises rent expense for Geostar employees providing administrative and technical support services to Gastar. At March 31, 2005, Geostar billed Gastar $1.4 million, which was equal to 12.5% of development costs for the Greer #1 and F-K #2 wells. These amounts were paid subsequent to the end of the quarter. In conjunction with the execution of the JOA, the Company terminated the convertible debenture arrangement with Geostar and commenced operating the East Texas properties. Under the new arrangement, the Company will be required to find financing for its share of future joint venture costs.

There is a balance of $2.7 million payable to Geostar as the operator pursuant to the JOA at March 31, 2005. Of the total revenue receivable at March 31, 2005, $3.0 million (2004 - $1.6 million) represents amounts that were due from Geostar as operator of the properties, once Geostar received the revenue from the third party gas purchaser. These amounts were settled subsequent to the end of the quarter.

(d)

In 2004, pursuant to the terms of the POA, Geostar billed the Company $27,000 (2003 - $369,000) for administrative overhead.

(e)

In 2004, FSW recorded $1.3 million (2003 - $Nil) in general and administrative costs for administrative and technical support provided by Geostar to the Company. Commencing April 1, 2004, FSW and Geostar agreed to replace the administrative fee with a cost sharing arrangement. As a result, Geostar charged FSW a proportionate amount of direct salary and shared premises rent expense for Geostar employees providing administrative and technical support services to Gastar based on actual costs incurred. This cost sharing arrangement continued as long as Geostar is the operator of the properties. This arrangement resulted in a charge of approximately $146,000 per month for the second and third quarter, $150,000 per month for the fourth quarter. The consolidated statements also include approximately $Nil in seismic reprocessing at March 31, 2005 ($115,000 – December 31, 2004 and $33,000 – December 31, 2003) fees paid to a subsidiary of Geostar. The seismic reprocessing fees were capitalized to natural gas and oil properties.

(f)

Effective January 1, 2005, the Company has agreed to hire and employ directly certain Geostar employees as members of the management team. The Company will invoice Geostar for their share of common costs, if applicable.

F-24

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

17. Income Taxes

The effective tax rate of income tax varies from the statutory rate as follows:


	As of December 31,
	2004			2003
	(in thousands except tax rate)
Combined effective tax rate		36.7	%		36.7	%

Expected income tax provision at statutory rates	$	(2,451	)	$	(1,437	)

Unrecorded loss carryovers		2,451			1,437

Actual income tax provision	$	—		$	—

The Company has the following approximate undeducted Canadian tax pools:


	As of December 31,
	2004		2003
	(in thousands)
Cumulative Canadian exploration expense	$	801	$	159

Cumulative Canadian development expense	$	171	$	107

Foreign exploration and development expense	$	660	$	525

Undeducted undepreciated capital cost	$	3	$	2

Undeducted non-capital loss carryforwards	$	8,090	$	6,111

If not utilized, the non-capital loss carryforwards for the above expire between 2005 and 2014.

The Company has the following approximate undeducted US tax pools:


	As of December 31,
	2004		2003
	(in thousands)
Undeducted capital costs	$	30,429	$	28,223

Undeducted loss carryforwards	$	45,891	$	23,274

If not utilized, the loss carryforwards for the above expire between 2020 and 2024.

The Company has the following approximate undeducted Australian tax pools:


	As of December 31,
	2004		2003
	(in thousands)
Undeducted capital costs	$	1,896	$	3,781

Undeducted loss carryforwards	$	3,121	$	2,885

The loss carryforwards for the above do not expire.

F-25

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The components of the Company’s future income tax are a result of the origination and reversal of temporary differences in Canada are comprised of the following:


	As of December 31,
	2004			2003
	(in thousands)
Nature of temporary differences
Capital assets	$	600		$	291
Share issue costs		7			13
Unused tax losses carryforward		2,970			2,243
Valuation allowance		(3,577	)		(2,547	)

Future income tax asset (liability)	$	—		$	—

The components of the Company’s future income tax are a result of the origination and reversal of temporary differences in the US are comprised of the following:


	As of December 31,
	2004			2003
	(in thousands)
Nature of temporary differences
Capital assets	$	(11,692	)	$	(1,528	)
Unused tax losses carryforward		16,842			8,542
Valuation allowance		(5,150	)		(7,014	)

Future income tax asset (liability)	$	—		$	—

The components of the Company’s future income tax are a result of the origination and reversal of temporary differences in Australia are comprised of the following:


	As of December 31,
	2004			2003
	(in thousands)
Nature of temporary differences
Capital assets	$	(108	)	$	(552	)
Unused tax losses carryforward		1,145			1,059
Valuation allowance		(1,037	)		(507	)

Future income tax asset (liability)	$	—		$	—

No future tax asset has been set up for the unutilized tax balances as their ultimate utilization of this asset is currently uncertain.

18. Commitments and Contingencies

(a)

The Company and its joint venture partner were awarded by the Provincial Government of Victoria, Australia four of seven mineral exploration licenses overlying the Gippsland Basin which required the Company and its partner to spend AUD $944,000 by the second quarter of 2004. In 2004, the Company renegotiated the terms of its Gippsland Basin spending commitment and obtained an extension until April 2005. The Company proposed to the Government of Victoria, a relinquishment of approximately

F-26

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

382,000 gross acres as a result of not meeting the spending commitment. This proposal was approved by the Government of Victoria. Gastar has a 75% working interest and is subsequently responsible for 75% of future expenditures.

(b)

The Company had committed to a work program on PEL 238 which included drilling three vertical wells and one horizontal well by August of 2005. The Company entered into an agreement with an outside third party who completed this work program as required.

(c)

The Company was a party to an arbitration claim brought by Forest Oil International Corp. (“Forest”) v. FSG. The arbitration has been settled and a Settlement and Release Agreement has been executed. The $1.0 million accrued at December 31, 2003 was settled via a net payment of $688,000 in 2004 (Note 6).

(d)

FSG is a named party to an arbitration proceeding captioned Estate of Virgil Sparks and Oil Wells of Kentucky, Inc. v FSG and Geostar. The dispute involves historical dealings with the development of an Authority to Prospect (“ATP”) Area in Queensland, Australia, as well as an ancillary agreement. The formal arbitration is in discovery stages. FSG and Geostar have moved to dismiss the arbitration on the grounds of a claimed prior settlement and release agreement. FSG and Geostar are vigorously defending the arbitration, and firmly believes that its position is sound. Further, the Company’s interest in ATP 560 were transferred from FSG to Conquest Exploration, Inc. (“Conquest”) in 2001, the result of which means that, although FSG is a named defendant, Conquest and Geostar would bear primary liability from this Arbitration action.

(e)

Gastar was a party to a lawsuit, as successor, captioned Jabiru Energy Development and Innovation Pty Ltd. (“Jabiru”) v. FSG. The Claim has been settled by the Company, with no admission of liability by any party. In 2003, FSG paid approximately $204,000 for settlement, legal fees and other costs related to this matter.

(f)

Under the terms of a third party agreement, to maintain its interests in the joint venture acreage, Gastar was obligated to provide a final payment on the leases acquired by August 15, 2004 and to spud a well by December 31, 2004 on the acquired leases to drill and test the Deep Bossier formation. At December 31, 2003, the Company had accrued approximately $600,000 for its share of the final payment on the leases. The final payment was paid in 2004 and a well was spud prior to December 31, 2004 satisfying this obligation.

(g)

In 2004, FST and Navasota Resources Inc. (“NRI”) entered into an agreement (“the 2004 Agreement”) that resulted in the amendment of the previous executed August 27, 2003 Agreement. Under the terms of the 2004 Agreement, FST agreed to pay, within 5 days of the execution of the 2004 Agreement, a total of $1.1 million to two banks for the account of NRI as compensation for the amendment to the August 27, 2003 Agreement, to resolve past joint interest billing disputes and as full and final settlement of amounts owed by FST to NRI under previous agreements. As a result of the 2004 Agreement, NRI’s overriding royalty interest in the leases held by FST and Gastar within the Area of Mutual Interest (“AMI”) under the July 7, 2000 joint operating agreement were reduced from 4.75% to 2.0%. In addition, NRI’s rights to participate on an after payout basis in certain leases within the AMI was reduced from 12.5% to 5.26316% and from 20% to 10%. Gastar is obligated to fund its 75% interest in the payments required under the 2004 Agreement and Gastar’s interest in the leases within the AMI will increase accordingly as a result of the reductions in NRI’s interest detailed above. At December 31, 2003, the Company had accrued its proportionate share of the final payment for the agreement of $743,000. In the second quarter of 2004, the Company paid its proportionate share of the final payment pursuant to the 2004 Agreement.

(h)

During the quarter, FST and FTD entered into an agreement with a third party for natural gas transportation and purchasing services. The Company will reimburse the party for the actual cost of the

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Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

taps, metering, measurement and other facilities necessary to receive the gas hereunder. The Company’s estimated portion of these costs is not to exceed $97,000.

(i)

As part of the Senior Note financing (Note 11), the subscribers received a 2% overriding royalty interest (“ORRI”) in the F-K #1, Cheney #1, and two future deep East Texas project wells in which Gastar participates. Gastar has a right of first refusal on any sale of the ORRI granted to the subscriber of the Senior Notes.

(j)

The Company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to contractual agreements and management decisions, result in the accrual of estimated future removal and site restoration costs. These costs are initially measured at a fair value and are recognized in the consolidated financial statements as the resent value of expected future cash flows. Subsequent to the initial measurement, the effect of the passage of time on the liability for the ARO (accretion expense) and the amortization of the ARO cost are recognized in the results of operations. Costs attributable to these commitments and contingencies are expected to be incurred over an extended period of time and are to be funded mainly from the Company’s cash provided by operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, it could be material for any quarter or year.

(k)

Under the terms of the proposed employment agreement to be executed in March 2005, the Company has agreed to indemnify an individual, who has acted at the Company’s request to be a officer of the Company, to the extent permitted by law, against any and all damages, liabilities, costs, charges or expenses suffered by or incurred by the individual as a result of their service. The nature of the indemnification agreements prevents the Company from making a reasonable estimate of the maximum potential amount it could be required to pay to beneficiary of such indemnification agreement. The Company has purchased various insurance policies to reduce the risks association with such indemnification.

(l)

FSW has entered into an employment agreement with a certain executive officer. In addition to defining the terms of employment, the agreement entitles the executive to termination payments, of up to two years compensation and the immediate vesting of all options previously granted, in the event of termination of employment upon death, disability, termination by the employer with or without cause or upon termination by the officer with adequate notice.

(m)

In 2004, the Company and certain of its subsidiaries acted as guarantors in certain senior note financing agreements totaling $25 million (Note 11).

Additionally, in the ordinary course of business, other indemnifications may have also been provided pursuant to provisions of purchase and sale contracts, service agreements, joint venture agreements, operating agreements and leasing agreements. In these agreements, the Company has indemnified counterparties if certain events occur. These indemnification provisions vary on an agreement by agreement basis. In some cases, there are no pre-determined amounts or limits included in the indemnification provisions and the occurrence of contingent events that will trigger payment under them is difficult to predict. Therefore, the maximum potential future amount that the Company could be required to pay cannot be estimated.

(n)

In 2004, the Company issued 1,989,475 warrants in conjunction with the $10 million Senior Note financing (Note 11). The Company obtained the required regulatory approvals and intended to issue these warrants at 110% of the market price on the closing date (i.e. the warrants are to be exercisable at $3.63 per share). It has come to the Company’s attention that the warrant certificate as issued reflects a price of $3.30 per share not $3.63. It is further the Company’s belief and position that this was an error. The Company’s intends to take all necessary steps to effect an amendment in the warrant certificate

F-28

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

consistent with its position. The impact of issuing warrants exercisable at $3.63 per share versus $3.30 per share amounts to $657,000 of reduced proceeds on the warrant exercise. In addition, had the Company valued these warrants with an exercise price of $3.30 per share (versus the $3.63 per share as recorded), the value attributable to the warrants would increase by approximately $268,000. As of June 8, 2005, a corrected warrant certificate had been executed for the corrected price of $3.63 per share.

(o)

The Company issued a letter of credit in regards to future office rental payments in the amount of $127,000 bearing interest at a rate of 2.71%, with a maturity date of January 15, 2006.

(p)

On May 3, 2005 Western Gas Resources, Lance Oil and Gas Company, Inc and Williams Production RMT Company filed a lawsuit against First Sourcenergy Wyoming, Inc., First Sourcenergy Group, Inc. and others over a dispute that has arisen concerning a June 2002 Lease Exchange and Purchase Agreement between certain of the parties. The issue involves a certain gas gathering agreement and its applicability to certain properties exchanged under the June 2002 Agreement. A formal response to the complaint is not due until June 2005. The Company believes that it has multiple strong defenses to this action and intends to vigorously advance its positions. Further, at this very preliminary stage, it would appear that the Company’s exposure is significantly lower than that of the other defendants.

(q)

In 2004, FST and FTD entered into gas treatment agreements with a third party for the F-K #1 and Cheney #1 wells. The primary term of the agreements is 2 years beginning on the first day of the month immediately following the month during which the plant becomes operational. The following is a schedule of future lease payments (in thousands):


2005	$	532
2006		483
2007		49

Total	$	1,064

19. Financial Instruments and Other Concentrations

The Company holds various forms of financial instruments. The nature of these instruments and the Company’s operations expose the Company to interest rate risk, credit risk and fair value risk. The Company manages its exposure to these risks by operating in a manner that minimizes its exposure to the extent practical.

(a) Interest rate risk management

Fixed rate debt and receivables are subject to interest rate price risk, as the value will fluctuate as a result of changes in market rates. At December 31, 2004, the Company had fixed interest rates on 100% of its interest bearing obligations at an effective rate of approximately 10 to 15%.

(b) Credit risk

Substantially all of the Company’s cash is held at one institution and therefore the Company is subject to concentrations of credit risk.

The fair value of the Company’s current financial assets and liabilities is approximated by their carrying values due to the short-term nature of the items. The fair value of the Company’s due to related party balance has not been disclosed as the amount is due to a private company and no reliable market information is available. The fair value of the Company’s other long-term investments is reflected by their carrying values as the instruments have recently been negotiated and, as such, reflect prevailing market rates.

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Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(d) Concentration risk

Approximately 59% of the Company’s 2004 revenues are from the production at the F-K #1 well in Texas. This well commenced production on September 28, 2004.

(e) During 2004, ETC Texas Pipeline Ltd. and Western Gas Resources, Inc. accounted for 59% and 10%, respectively, of the Company’s oil and natural gas revenues. During 2003, Western Gas Resources, Inc. and Equitable Gas Company a division of Equitable Resources, Inc. accounted for 72% and 17%, respectively, of the Company’s natural gas and oil revenues. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

20. Statement of Cash Flows

Non-cash transactions have been disclosed in Notes 4, 5, 7 - 14, 16 and 18.

21. Subsequent Events

On April 19, 2005 Gastar announced that it had entered into a Letter of Intent (“LOI”) with Geostar for the acquisition of Geostar’s interest in the East Texas play and in the Powder River Basin of Wyoming for $37.5 million in cash and $6 million in stock at closing and an additional $25 million cash payment in January 2006. In addition, Geostar will receive a payment in stock during the first quarter of 2007 under a look-back provision on the East Texas assets, based on a required number of drilled wells, and net reserve additions valued at $1.50 per Mcf less attributable capital expenditures to Geostar’s former ownership position on the East Texas development costs. In a separate transaction, Gastar announced its intention to acquire an option to purchase up to 50% interest in the brown coal mining rights to existing and future mining licenses held by a Geostar subsidiary in the Gippsland Basin of Victoria, Australia. The price of the option is $2.5 million at closing and $2.5 million in January 2006 for up to 25% interest and another $5 million payable on or before July 31, 2006 for an additional 25% interest. The option is exercisable for 90 days following the delivery to Gastar of a final feasibility study on the initial mining and processing facility. If exercised, the option cost will be US $1.00 per ton of coal reserves to be mined and processed in the initial facility related to the feasibility study. The option will be payable in a combination of cash and stock, not to exceed 50% in cash.

On June 17, 2005, the Company completed the private placement of $63.0 million in principal amount of senior secured notes (“Secured Notes”) and 1,217,269 common shares. The Secured Notes bear interest at three month LIBOR plus 6% and mature on June 18, 2010. The Company also committed to issue to the purchasers of the Secured Notes, for no additional consideration, common shares in CDN$4.5 million increments on each of the six, twelve and eighteen-month anniversaries of the original Secured Notes closing date valued on a five day weighted average trading price prior to the date of issuance.

The Company has the right, exercisable quarterly during the period from August 17, 2005 to June 16, 2007, to require the original purchaser of the Secured Notes to purchase additional Secured Notes in an amount limited to an aggregate of $20.0 million in principal, provided that the Company complies with certain financial and other covenants. If additional Secured Notes are issued, the purchasers will also be entitled to receive, for no additional consideration, additional common shares on similar terms as those issued with the original Secured Notes in a pro rata amount based on the additional principal amount of the Secured Notes. To issue these additional Secured Notes, we must meet certain requirements including a minimum ratio of our present value discounted at 10%, based on prices specified in the Secured Notes, proved plus probable reserves to net debt ratio must be at least 2.0:1.

Concurrently with the private placement of Secured Notes, the Company closed the acquisition of additional leasehold and working interest properties from Geostar in the Hilltop area of East Texas and in the Powder River

F-30

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Basin of Wyoming and Montana. The Company paid a total of $68.5 million for the interests acquired from Geostar consisting of $30.5 million in cash, 1,650,133 common shares valued at CDN$4.50 per share and $32.0 million in unsecured subordinated notes maturing on January 31, 2006. The acquisition increased Gastar’s working interest position in the Hilltop area to an average of over 90% and gave us operational control of the properties. The acquisition of additional Powder River Basin interests provides Gastar with a larger interest in properties currently being developed through an existing joint venture.

On August 11, 2005, the Company executed an agreement with Geostar whereby the Geostar $32.0 million unsecured subordinated note was cancelled. In conjunction with the note cancellation, the Company agreed to issue Geostar $17.0 million of our common shares issued at a value of CDN $3.25 and a new unsecured subordinated note for $15.0 million. The new Geostar note bears interest, payable monthly commencing February 15, 2006, at three-month LIBOR plus 4.5% and matures November 15, 2006. The note requires monthly principal payments of $1.5 million commencing February 15, 2006 and continuing for nine months thereafter with a final principal payment of $1.5 million due on November 15, 2006. The Company may elect to pay interest in kind through the issuance of additional notes with such notes maturing on January 15, 2007.

On June 30, 2005, Gastar completed a private placement of 6,617,736 common shares at CDN$3.31 per share. The estimated net proceeds from this placement were $16.4 million (CDN$20.5 million), after deducting placement fees and expenses.

22. Supplemental Oil and Gas Disclosures – Unaudited

Oil and Gas Producing Activities

The following disclosures for the Company are made in accordance with SFAS No. 69, “Disclosures About Oil and Gas Producing Activities (An Amendment of FASB Statements 19, 25, 33 and 39)” (“SFAS No. 69”). Users of this information should be aware that the process of estimating quantities of proved, proved developed and proved undeveloped crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

Proved reserves represent estimated quantities of natural gas and crude oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.

Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made.

Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.

F-31

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Estimates of proved developed and proved undeveloped reserves as of December 31, 2004, 2003 and 2002, were based on estimates prepared by Netherland, Sewell & Associates Inc. (“NSAI”) an independent petroleum reservoir engineer.

Our independent engineer is engaged by and provides their reports to the Reserve Committee of the Board of Directors. The reservoir engineer is independent and engaged to prepare the reserves reports rather than to audit reports prepared by the Company. Company management represents to the independent engineers that we have provided all relevant operating data and documents, and management reviews the reports to ensure completeness and accuracy. The final independent engineer report is approved by the Reserve Committee.

Our relevant management controls over proved reserve attribution, estimation and evaluation include:

•

controls over and processes for the collection and processing of all pertinent operating data and documents needed by our independent reservoir engineers to estimate our proved reserves;

•

engagement of well qualified and independent reservoir engineers for review of our operating data and documents and preparation of reserve reports annually in accordance with all SEC reserve estimation guidelines; and

•

review by our senior management of the independent reservoir engineers’ reserves reports for completion and accuracy.

Market prices as of each year-end were used for future sales of natural gas, crude oil and natural gas liquids. Future operating costs, production and ad valorem taxes and capital costs were based on current costs as of each year-end, with no escalation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. Reserve data represent estimates only and should not be construed as being exact. Moreover, the standardized measure should not be construed as the current market value of the proved oil and gas reserves or the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risk.

F-32

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Capitalized Costs Relating Oil and Producing Activities

The following table presents the Company’s aggregate capitalized costs relating to oil producing activities and the related depreciation, depletion and amortization:


	United States		Australia		Total
	(in thousands)
At December 31, 2004
Proved properties	$	41,748	$	615	$	42,363
Unproved properties		27,666		2,093		29,759

		69,414		2,708		72,122
Less accumulated depreciation, depletion and amortization		4,246		—		4,246
Less impairment allowance		10,716		604		11,320

Total	$	54,452	$	2,104	$	56,556


At December 31, 2003
Proved properties	$	14,351	$	604	$	14,955
Unproved properties		21,666		5,200		26,866

		36,017		5,804		41,821

Less accumulated depreciation, depletion and amortization		1,015		—		1,015
Less impairment allowance		4,411		604		5,015

Total	$	30,591	$	5,200	$	35,791


At December 31, 2002
Proved properties	$	13,816	$	504	$	14,320
Unproved properties		20,260		4,765		25,025

		34,076		5,269		39,345
Less accumulated depreciation, depletion and amortization		444		—		444
Less impairment allowance		3,959		504		4,463

Total	$	29,673	$	4,765	$	34,438

Pursuant to SFAS No. 143, net capitalized cost includes related asset retirement cost of $1.5 million, $828,000 and $77,000 at December 31, 2004, 2003 and 2002, respectively.

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in SFAS No. 19. Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include exploration expenses and additions to exploration wells, including those in progress. Development costs include additions to production facilities and equipment, as well as additions to development wells, including those in progress. The following table sets forth costs incurred related to the Company’s oil and gas activities for the years ended December 31, 2004, 2003, and 2002:

F-33

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Costs incurred in oil and gas-producing activities are as follows:


	United States		Australia			Total
	(in thousands)
For the year ended December 31, 2004
Proved property acquisition	$	1,460	$	2		$	1,462
Unproved property acquisition		3,163		(288	)		2,875
Exploration		27,662		195			27,857
Development		2,437		—			2,437

Total	$	34,722	$	(91	)	$	34,631


	United States		Australia		Total
	(in thousands)
For the year ended December 31, 2003
Proved property acquisition	$	826	$	3	$	829
Unproved property acquisition		3,600		100		3,700
Exploration		6,012		346		6,358
Development		458		—		458

Total	$	10,896	$	449	$	11,345


	United States		Australia		Total
	(in thousands)
For the period ended December 31, 2002
Proved property acquisition	$	1,223	$	46	$	1,269
Unproved property acquisition		5,895		153		6,048
Exploration		2,681		256		2,937
Development		1,780		—		1,780

Total	$	11,579	$	455	$	12,034

Costs incurred include capitalized general and administrative costs of $6,000 in 2004 all of which were related to US Operation. No capitalized general and administrative costs were incurred in 2003 and 2002

Costs relating to unevaluated properties which have been excluded from amortization at December 31, 2004 are as follows:


	As of December 31,
	2004			2003		2002		2001 and prior		Total
	(in thousands)
Property acquisition	$	(125	)	$	1,059	$	7,853	$	7,964	$	16,751
Exploration		5,713			415		459		1,464		8,051
Development		874			135		734		3,136		4,879
Other capitalized costs		—			—		—		78		78

Total	$	6,462		$	1,609	$	9,046	$	12,642	$	29,759

F-34

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The US properties are expected to be developed over the next two to five years while the Australian properties are anticipated to be developed over the next three to seven years.

Results of Operations for Oil and Gas Producing Activities

The following table sets forth results of operations for oil and gas producing activities for the years ended December 31, 2004, 2003 and 2002:


	United States
	(in thousands)
For the year ended December 31, 2004
Oil and gas sales	$	6,059
Production expenses		(2,000	)
Impairment of natural gas and oil properties		(6,306	)
Depletion, depreciation and amortization		(3,231	)

Results of producing activities	$	(5,478	)

Depletion, depreciation and amortization per Mcfe	$	2.89

For the year ended December 31, 2003
Oil and gas sales	$	1,461
Production expenses		(712	)
Impairment of natural gas and oil properties		(552	)
Depletion, depreciation and amortization		(570	)

Results of producing activities	$	(373	)

Depletion, depreciation and amortization per Mcfe	$	1.46

For the year ended December 31, 2002
Oil and gas sales	$	783
Production expenses		(769	)
Impairment of natural gas and oil properties		(377	)
Depletion, depreciation and amortization		(358	)

Results of producing activities	$	(721	)

Depletion, depreciation and amortization per Mcfe	$	0.87

The results of producing activities exclude interest charges and general corporate expenses and represent US activities only due to no producing operations activities in Australia to date.

Net Proved and Proved Developed Reserve Summary

The Company’s proved net developed and proved undeveloped reserves are located only in the United States. The Company cautions that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are expected to change as future information becomes available. Material revisions of reserve estimates may occur in the future; development and production of the oil and gas reserves may not occur in the periods assumed and actual prices realized and actual costs incurred may vary significantly from those used. Proved

F-35

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods being utilized at the time the estimates were made.

The following table sets forth changes in estimated net proved and proved developed reserves for the years ended December 31, 2004, 2003 and 2002:


	Gas (Mmcf)		Oil (MBbl)
December 31, 2001	8,461		44

Extensions and discoveries	7,261		—
Purchases of minerals in place	481		—
Revisions of previous estimates	(634	)	(15	)
Production	(393	)	(3	)

December 31, 2002	15,176		26

Extensions and discoveries	5,067		—
Sales of minerals in place	(9,082	)	—
Revisions of previous estimates	(2,912	)	(21	)
Production	(385	)	(1	)

December 31, 2003	7,864		4

Extensions and discoveries	14,931		4
Purchases of minerals in place	2,528		—
Sales of minerals in place	(2,408	)	—
Revisions of previous estimates	(407	)	—
Production	(1,108	)	(2	)

December 31, 2004	21,400		6

Proved developed reserves:
December 31, 2002	4,650		26

December 31, 2003	1,865		4

December 31, 2004	6,179		6

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on natural gas and crude oil reserve and production volumes estimated by the independent petroleum reservoir engineers. This information may be useful for certain comparison purposes but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company’s oil and gas assets.

The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of natural gas

F-36

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

and crude oil reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The Standardized Measure of Discounted Future Net Cash Flows relating to proved oil and gas reserves is presented below:


	United States (in thousands)
December 31, 2002:

Future cash inflows	$	39,004
Future production costs		(14,312	)
Future development costs		(7,727	)
Future income taxes		(586	)

Future net cash flows		16,379

10% annual discount for estimated timing of cash flows		(5,884	)

Standardized measure of discounted future cash flows	$	10,495

December 31, 2003:

Future cash inflows	$	36,842
Future production costs		(16,927	)
Future development costs		(8,475	)
Future income taxes		—

Future net cash flows		11,440

10% annual discount for estimated timing of cash flows		(3,303	)

Standardized measure of discounted future cash flows	$	8,137

December 31, 2004:

Future cash inflows	$	106,830
Future production costs		(32,654	)
Future development costs		(39,680	)
Future income taxes		—

Future net cash flows		34,496

10% annual discount for estimated timing of cash flows		(8,887	)

Standardized measure of discounted future cash flows	$	25,609

F-37

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Changes in Standardized Measure of Discounted Future Net Cash Flows

The principal sources of changes in the Standardized Measure of Future Net Cash Flows are as follows:


	United States (in thousands)
December 31, 2001	$	5,120
Extensions and discoveries, less related costs		3,593
Sales of oil and gas, net of production costs		(14	)
Purchases of minerals in place		478
Revisions in previous quantity estimates		(732	)
Net change in income tax		(111	)
Net changes in prices and production costs		2,208
Accretion of discount		480
Development costs incurred		294
Net change in estimated future development costs		(1,107	)
Change in production rates (timing)—other		286

December 31, 2002		10,495

Extensions and discoveries, less related costs		5,378
Sales of oil and gas, net of production costs		(749	)
Sales of minerals in place		(10,054	)
Revisions in previous quantity estimates		(4,675	)
Net change in income tax		111
Net changes in prices and production costs		2,129
Accretion of discount		1,273
Development costs incurred		1,713
Net change in estimated future development costs		3,689
Change in production rates (timing)—other		(1,173	)

December 31, 2003		8,137

Extensions and discoveries, less related costs		21,371
Sales of oil and gas, net of production costs		(4,059	)
Purchases of minerals in place		2,853
Sales of minerals in place		(2,718	)
Revisions in previous quantity estimates		(1,458	)
Net change in income tax		—
Net changes in prices and production costs		291
Accretion of discount		864
Development costs incurred		337
Net change in estimated future development costs		1,684
Change in production rates (timing) - other		(1,693	)

December 31, 2004	$	25,609

F-38

Index to Financial Statements

GASTAR EXPLORATION LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Average prices in effect at December 31, 2004, 2003 and 2002 used in determining future net revenues related to the standardized measure calculations are as follows:


	2004		2003		2002
Oil (per Bbl)	$	39.75	$	29.25	$	27.50
Gas (per Mcf)
Powder River Basin (Wyoming and Montana)	$	5.52	$	5.58	$	3.12
Hilltop Area (East Texas)	$	5.82	$	5.97	$	4.74
Appalachian Basin (West Virginia)	$	6.45	$	5.71	$	4.80
Cherokee Basin (Kansas)	$	6.18	$	5.97	$	4.74

F-39

Index to Financial Statements

Appendix A

GLOSSARY OF NATURAL GAS AND OIL TERMS

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bod. One stock tank barrel per day.

BOE. One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, which approximates the relative energy content between crude natural gas and oil.

Bcf. One billion cubic feet of natural gas.

Bituminous coal. Higher rank coals.

Bwd. Barrels of water per day.

CBM. Coal bed methane.

CDN$. Canadian dollars.

Completion. The installation of permanent equipment for the production of oil or gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developed acreage. The number of acres that are allocated or assignable to producing wells or wells capable of production.

Developed well. A well drilled within the proved area of a natural gas and oil reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Exploration. The search for accumulations of natural gas and oil reserves by any geologic, geophysical, or other means.

Exploratory well. A well drilled to find and produce natural gas and oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas and oil in another reservoir or to extend a known reservoir.

Farmout agreement. An agreement between a leaseholder and a party willing to drill natural gas and oil wells on a leasehold property in exchange for assignments from the leaseholder of part or all of the leasehold interests. The agreement is an executory contract in that performance will take place in the future. A farmout agreement will typically (1) outline the future drilling obligations and (2) provide the framework in which the leaseholder will effect the future leasehold assignments, assuming the drilling obligations are met. The leaseholder typically reserves overriding royalty interests at the time that the leaseholder finally executes an assignment.

Field. An area consisting of single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

A-1

Index to Financial Statements

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizon. A geological layer or strata that may or may not contain oil or natural gas.

Mcf. One thousand cubic feet of natural gas.

Mcfd. One thousand cubic feet of natural gas per day.

Mcfe. One thousand cubic feet of natural gas equivalent determined using the ratio of six Mcf of natural gas to one Bbl of oil, which approximates the relative energy content between natural gas and oil.

MBbl. One thousand stock tank barrels, or 42,000 U. S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

MMcf. One million cubic feet of natural gas.

MMcfd. One million cubic feet of natural gas per day.

MMcfe. One million cubic feet of natural gas equivalent determined using the ratio of six Mcf of natural gas to one Bbl of oil, which approximates the relative energy content between natural gas and oil.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.

Net smelter return. An interest in a mining property held by the vendor on the net revenues generated from the sale of metal produced by the mine.

NYMEX. The New York Mercantile Exchange, which is the primary exchange on which natural gas futures contracts are traded.

Present value or PV(10). When used with respect to natural gas and oil reserves, the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.

Productive well. A well that is, or is capable of, producing hydrocarbons in sufficient quantifies such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed producing reserves. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and able to produce to market.

Proved developed nonproducing reserves. Proved developed reserves expected to be recovered from zones behind casing in existing wells.

Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

A-2

Index to Financial Statements

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Rank. A measure of the maturity, or age and degree of carbonization, of coals.

Recompletion. The completion for production of an existing well bore in another formation from that in which the well has been previously completed.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty interest. An interest in an oil or natural gas property entitling the owner to a share of gas production free of costs of production.

Subbituminous coal. Lower rank coals.

Tcf. Trillion cubic feet of natural gas.

3-D (three dimensional) seismic. Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two dimensional seismic data.

2-D (two dimensional) seismic. The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflected seismic data collected along a single source profile.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas regardless of whether such acreage contains proved reserves.

Vitrinite reflectance. Technical test of the reflectivity of a coal surface, generally associated with the rank of a coal.

Working interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production. A working interest pays its share of the costs of drilling and production, as compared to an overriding royalty or royalty interest, which does not pay any costs associated with drilling or production.

Workover. Operations on a producing well to restore or increase production from the currently producing formation.

A-3

Index to Financial Statements

24,022,444 Shares

Gastar Exploration Ltd.

Common Shares

Prospectus

, 2005

Until (25 days after the commencement of this offering), all dealers that effect transactions in our common shares, whether or not participating in this offering, may be required to deliver a prospectus.

Index to Financial Statements

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

Set forth below are the expenses expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the amounts set forth below are estimates.


Registration fee	$	7,400
Printing expenses		11,000
Fees and expenses of legal counsel
Accounting fees and expenses
Miscellaneous

Total	$	*

*	To be completed by pre-effective amendment.

Item 14. Indemnification of Directors and Officers.

In April 2003, we entered into Indemnity Agreements with each of our directors and executive officers. Pursuant to these Indemnity Agreements, which are governed by the laws of Alberta, Canada, we will, subject to the Business Corporations Act (Alberta), indemnify and hold harmless the director or officer:

•

From and against any and all claims that may be made against such director or officer by any person or other entity (including governmental entities) arising out of or in any way in connection with such individual having been a director and/or officer of us or another entity;

•

From and against any and all liability (except where such liability relates to a failure of the director or officer to act honestly and in good faith with a view to the best interests of us), losses, damages, costs, charges, expenses, fines and penalties, including an amount paid to settle an action or satisfy a judgment, and the fees, charges and disbursements of legal counsel, which the director or officer may reasonably sustain, incur or be liable for in consequence of acting as an officer and/or director of us or another entity; and

•

Without limiting the generality of the foregoing, from and against all liabilities and penalties at any time imposed upon the director or officer or any claims at any time made against the director or officer by virtue of the Business Corporations Act (Alberta), the Workers’ Compensation Act (Alberta), the Bankruptcy Act (Canada), the Income Tax Act (Canada) and the Alberta Corporate Income Tax Act, or any re-enactment or amendment of any such statues and which in any way involve the affairs of business of us or another entity.

The above indemnities will continue in effect after the director or officer resigns his position or his position is terminated for any reason.

II-1

Index to Financial Statements

Item 15. Recent Sales of Unregistered Securities.

During the three years preceding the date of this registration statement, the registrant has sold the following securities without registration under the Securities Act:

In September 2002, the registrant completed an offering of an additional $1,570,920 in aggregate principal amount of its 12% unsecured convertible notes. These convertible notes had a two-year term. They were converted at the rate of one common share for each $1.97 of the principal amount of the notes during the 30-day period immediately before maturity. The Private Consulting Group, Inc. acted as placement agent for this offering. The purchasers of these notes were U.S. residents. The issuance of the notes was exempt from registration pursuant to Rule 506 of Regulation D under the Securities Act.

Also in September 2002, the registrant completed an offering of $4,010,050 of working interests in a four-well drilling program on its Bossier sand natural gas properties. In connection with the offering, an aggregate of 2,005,027 warrants were issued to subscribers on a pro-rata basis, with each warrant having a three-year term and entitling the holder to acquire one share of the registrant’s common shares at an exercise price of CDN$2.35 per share. The registrant paid to the working interest owner an advance on production revenue equal to 10% of the amount invested on a quarterly basis for the first 12 months of the investment. All of the working interests and warrants were issued to U.S. residents. The Private Consulting Group, Inc. acted as placement agent for this offering. This issuance was exempt from registration pursuant to Rule 506 of Regulation D under the Securities Act.

On September 30, 2002, the registrant exercised its option under the CDN$25.0 million floating convertible debenture agreement with Geostar to issue shares of its common shares for partial payment of amounts owed to Geostar at that time. The registrant issued 1,343,219 shares of its common shares to Geostar at the September 30, 2002 closing market price of CDN$2.35 per share for amounts owing of $2,000,000. There was no underwriter involved in this transaction. This issuance was exempt from registration under Section 4(2) of the Securities Act.

On December 31, 2002, the registrant exercised its option under the CDN$25.0 million floating convertible debenture agreement with Geostar to issue shares of its common shares for payment of amounts owed to Geostar at that time. The registrant issued 3,798,895 shares of its common shares to Geostar at the December 31, 2002 closing market price of CDN$2.20 per share for amounts owing of $5,300,000. There was no underwriter involved in this transaction. This issuance was exempt from registration under Section 4(2) of the Securities Act.

On June 30, 2003, the registrant again exercised its option under the CDN$25.0 million floating convertible debenture agreement with Geostar to issue shares of its common shares for full payment of amounts owed to Geostar at that time. The registrant issued 4,236,946 shares of its common shares to Geostar at the June 30, 2003 closing market price of CDN$2.10 per share for amounts owing of $6,603,032. There was no underwriter involved in this transaction. The issuance was exempt from registration under Section 4(2) of the Securities Act.

On November 26, 2003, the registrant again exercised its option under the CDN$25.0 million floating convertible debenture agreement with Geostar to issue shares of its common shares for full payment of amounts owed to Geostar as of September 30, 2003. The registrant issued 852,514 shares of its common shares to Geostar at the November 26, 2003 closing market price of CDN$2.40 per share for amounts owing of $1,568,805. There was no underwriter involved in this transaction. The issuance was exempt from registration under Section 4(2) of the Securities Act.

II-2

Index to Financial Statements

On December 31, 2003, the registrant again exercised its option under the CDN$25.0 million floating convertible debenture agreement with Geostar to issue shares of its common shares for full payment of amounts owed to Geostar at that time. The registrant issued 116,640 shares of its common shares to Geostar at the December 31, 2003 closing market price of CDN$2.52 per share for amounts owing of $227,045. There was no underwriter involved in this transaction. The issuance was exempt from registration under Section 4(2) of the Securities Act.

On April 11, 2004, $6,710,000 in aggregate principal amount of the registrant’s 12% unsecured convertible notes issued in March 2002 converted into 6,099,999 common shares at a conversion price of $1.10 per share.

On October 5, 2004, $1,570,920 in aggregate principal amount of the registrant’s 12% unsecured convertible notes issued in September 2002 converted into 747,216 common shares at a conversion price of $1.97 per share.

On November 12, 2004, the registrant issued $24,930,000 aggregate principal amount of its 9.75% Senior Convertible Unsecured Subordinated Debentures due 2009. The notes are convertible into shares of the registrant’s common shares at a current conversion price of $4.38 per share. Westwind Partners Inc. acted as placement agent for this offering. The issuance of the convertible debentures was exempt from registration pursuant to Rule 506 of Regulation D and Regulation S under the Securities Act.

On November 16, 2004, the registrant issued $5,070,000 aggregate principal amount of its 9.75% Senior Convertible Unsecured Subordinated Debentures due 2009. The notes are convertible into shares of the registrant’s common shares at a current conversion price of $4.38 per share. Westwind Partners Inc. acted as placement agent for this offering. The issuance of the convertible debentures was exempt from registration pursuant to Rule 506 of Regulation D and pursuant to Regulation S under the Securities Act.

On June 17, 2005, the registrant issued $63.0 million of Senior Secured Notes bearing interest at three-month LIBOR plus 6% due 2010. In conjunction with the note placement, the registrant issued 1,217,269 common shares to the purchasers of the notes, for no additional consideration, and also committed to issue to the purchasers of the notes, for no additional consideration, common shares in CDN$4.5 million increments on each of the six, twelve and eighteen-month anniversaries of the closing date, subject to the registrant’s compliance with certain financial and other covenants. The issuance of the senior secured notes and the common shares together with subscription receipts were exempt from registration pursuant to Rule 506 of Regulation D under the Securities Act.

On June 17, 2005, concurrent with the private placement of its senior secured notes, the registrant issued 1,650,133 common shares valued at CDN$4.50 per share and $32.0 million in unsecured subordinated notes maturing on January 31, 2006 representing a portion of the purchase price in connection with the acquisition of additional leasehold and working interest properties from Geostar. The issuance of the shares and unsecured subordinated notes to Geostar was exempt from registration pursuant to Section 4(2) under the Securities Act.

On June 30, 2005, the registrant issued 6,617,736 common shares at CDN$3.31 per share in a private offering. Pritchard Capital, LLC and Westwind Partners Inc. acted as placement agents for this offering. The issuance of the shares was exempt from registration pursuant to Rule 506 of Regulation D and pursuant to Regulation S under the Securities Act.

On August 11, 2005, we executed an agreement with Geostar Corporation whereby a $32.0 million unsecured subordinated note of the registrant was cancelled. In conjunction with the note cancellation, the registrant agreed to issue Geostar $17.0 million of registrant’s common shares issued at a value of CDN$3.25 and a new unsecured subordinated note for $15.0 million.

II-3

Index to Financial Statements

Options to purchase a total of 17,329,600 shares of the registrant’s common shares have been issued under the 2002 Stock Option Plan, of which options to purchase 6,392,500 shares have been exercised. These issuances were exempt under Section 4(2) of the Securities Act and Rule 701 issued under the Securities Act. The issuance of the shares and unsecured subordinated notes to Geostar was exempt from registration pursuant to Section 4(2) under the Securities Act.

Item 16. Exhibits

The following documents are filed as exhibits to this registration statement:


Exhibit Number		Description

3.1*		Amended and Restated Articles of Incorporation of Gastar Exploration Ltd.

3.2		Bylaws of Gastar Exploration Ltd.

4.1		Indenture dated as of November 12, 2004 between Gastar Exploration Ltd. and CIBC Mellon Trust Company, as trustee.

4.2		Form of 9.75% Convertible Senior Unsecured Subordinated Debenture of Gastar Exploration Ltd.

4.3		Form of placement agent warrant to Purchase Common shares of Gastar Exploration Ltd. in connection with issuances of 9.75% Convertible Senior Unsecured Subordinated Notes of Gastar Exploration Ltd.

4.4		Agency Agreement dated as of November 12, 2004 between Gastar Exploration Ltd. and Westwind Partners Inc. in connection with issuances of 9.75% Convertible Senior Unsecured Subordinated Notes of Gastar Exploration Ltd.

4.5		Form of Subscription Agreement for U.S. purchasers of 9.75% Convertible Senior Unsecured Subordinated Debentures of Gastar Exploration Ltd.

4.6		Form of Subscription Agreement for Non-U.S. purchasers of 9.75% Convertible Senior Unsecured Subordinated Debentures of Gastar Exploration Ltd.

4.7		Securities Purchase Agreement dated as of June 17, 2005, by and among Gastar Exploration Ltd. and the purchasers named therein for the purchase of $63.0 million in principal amount of Senior Secured Notes.

4.8		Form of Senior Secured Note dated as of June 17, 2005.

4.9		Registration Rights Agreement dated as of June 17, 2005, by and among Gastar Exploration Ltd. and the purchasers named therein.

4.10		Form on Subscription Agreement for U.S. Purchasers of common shares of Gastar Exploration Ltd. in a private placement dated June 30, 2005.

4.11		Form of Subscription Agreement for non-U.S. Purchasers of common shares of Gastar Exploration Ltd. in a private placement dated June 30, 2005.

4.12		Placement agent warrant to purchase 510,525 common shares of Gastar Exploration Ltd. in connection with the sale of $15.0 million in principal amount of 15% subordinate notes in October 2004.

4.13		Placement agent warrant to purchase 1,989,475 common shares of Gastar Exploration Ltd. in connection with the sale of $10.0 million in principal amount of 15% subordinate notes in February 2005.

4.14		Form on 10% subordinated note issued June 2004.

II-4

Index to Financial Statements


Exhibit Number		Description

4.15		Form of warrant to purchase common shares of Gastar Exploration Ltd. issued in connection with the sale of 10% subordinated notes in June 2004

4.16		Form of warrant to purchase common shares of Gastar Exploration Ltd. issued in connection with the private placement of working interests in 2002.

5.1	*	Opinion of Burnet, Duckworth & Palmer LLP

10.1		The Gastar Exploration Ltd. 2002 Stock Option Plan

10.2		Employment Agreement dated March 23, 2005 by and among First Sourcenergy Wyoming, Inc., Gastar Exploration, Ltd. and J. Russell Porter.

10.3		Employment Agreement dated April 26, 2005 by and among First Sourcenergy Wyoming, Inc., Gastar Exploration, Ltd. and Michael A. Gerlich.

21.1		Subsidiaries of Gastar Exploration Ltd.

23.1		Consent of BDO Dunwoody LLP

23.2		Consent of Netherland, Sewell and Associates, Inc.

23.3		Consent of Burnet, Duckworth & Palmer LLP (included in Exhibit 5.1)

24.1		Power of Attorney (included on signature page).

*	To be filed by amendment.

Item 17. Undertakings

Insofar as indemnification by the registrant for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer, or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer, or controlling person in connection with the securities being registered hereunder, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes:

(1)

To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i)

To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933;

(ii)

To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20% change in the maximum aggregate

II-5

Index to Financial Statements

offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement;

(iii)

To include any material information with respect to the distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;

(2)

That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3)

To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

The registrant hereby undertakes that:

(1)

For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2)

For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-6

Index to Financial Statements

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, Texas on August 12, 2005.


Gastar Exploration Ltd.

By:		/S/ J. RUSSELL PORTER
		Name: J. Russell Porter Title: Chief Executive Officer and President

Each person whose signature appears below appoints J. Russell Porter and Michael A. Gerlich, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them of their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on the dates indicated.


Signature	Title	Date

/S/ J. RUSSELL PORTER J. Russell Porter	Chief Executive Officer, President, Chief Operating Officer and Director (Principal Executive Officer)	August 12, 2005

/S/ MICHAEL A. GERLICH Michael A. Gerlich	Vice President and Chief Financial Officer and Director (Principal Financial and Accounting Officer)	August 12, 2005

/S/ THOMAS E. ROBINSON Thomas E. Robinson	Chairman of the Board of Directors	August 12, 2005

/S/ RICHARD KAPUSCINSKI Richard Kapuscinski	Director	August 12, 2005

/S/ MATTHEW J. P. HEYSEL Matthew J. P. Heysel	Director	August 12, 2005

/S/ THOMAS CROW Thomas Crow	Director	August 12, 2005

/S/ ABBY BADWI Abby Badwi	Director	August 12, 2005

II-7