Gastar Exploration Inc.
GASTAR EXPLORATION LTD (Form: 10-K, Received: 03/17/2008 16:31:40)
Table of Contents
Index to Financial Statements

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

 

x Annual report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934

 

     For the Fiscal Year Ended December 31, 2007

or

 

¨ Transition report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934

 

     For the transition period from                      to                     

Commission file number: 001-32714

GASTAR EXPLORATION LTD.

(Exact name of registrant as specified in its charter)

 

Alberta, Canada   98-0570897

(State or other jurisdiction of

incorporation or organization)

  (IRS Employer Identification No.)

1331 Lamar Street, Suite 1080

Houston, Texas 77010

  77010
(Address of principal executive offices)   (Zip Code)

(713) 739-1800

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

 

                    Title of each class                

 

Name of each exchange on which registered

Common Shares, No Par Value   American Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act.    Yes   ¨     No   x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes   ¨     No   x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes   x     No   ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer   ¨     Accelerated filer   x     Non-accelerated filer   ¨     Smaller reporting company   ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).    Yes   ¨     No   x

The aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the closing price of $2.05 per common share on the American Stock Exchange at the close of business on June 29, 2007 (the last business day of the registrant’s most recently completed second fiscal quarter) was $347,739,705.

As of March 13, 2008, there were 208,194,570 common shares outstanding.

Documents incorporated by reference. None

 

 

 


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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2007

TABLE OF CONTENTS

 

          Page
   PART I   

Item 1.

  

Business

   1
  

Overview

   1
  

Our Strategy

   1
  

Natural Gas and Oil Activities

   2
  

Markets and Customers

   5
  

Competition

   7
  

Governmental Regulations

   7
  

Environmental Regulations

   10
  

Employees

   15
  

Corporate Offices

   15
  

Internet Website

   15

Item 1A.

  

Risk Factors

   16

Item 1B.

  

Unresolved Staff Comments

   30

Item 2.

  

Properties

   30
  

Production, Prices and Operating Expenses

   31
  

Drilling Activity

   31
  

Exploration and Development Acreage

   32
  

Productive Wells

   32
  

Natural Gas and Oil Reserves

   33

Item 3.

  

Legal Proceedings

   34

Item 4.

  

Submission of Matters to a Vote of Security Holders

   34
   PART II   

Item 5.

  

Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

   35
  

Market Information

   35
  

Shareholders

   35
  

Dividends

   35
  

Recent Sales of Unregistered Securities; Use of Proceeds from Unregistered Securities

   35

Item 6.

  

Selected Financial Data

   36

Item 7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

   36
  

Overview

   37
  

Critical Accounting Policies and Estimates

   38
  

Results of Operations

   42
  

Liquidity and Capital Resources

   44
  

Off Balance Sheet Arrangements

   46
  

Contractual Obligations

   46

 

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          Page
  

Commitments

   47
  

Future Share Issuance

  
  

Common Share Registration Obligation and Penalties

   47
  

New Accounting Pronouncements

   48

Item 7A.

  

Quantitative and Qualitative Disclosures about Market Risk

   48
  

Commodity Price Risk

   48
  

Interest Rate Risk

   48
  

Currency Translation Risk

   49

Item 8.

  

Financial Statements and Supplementary Data

   49

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

   49

Item 9A.

  

Controls and Procedures

   49
  

Management’s Conclusions on the Effectiveness of Disclosure of Controls and Procedures

   49
  

Changes in Internal Controls over Financial Reporting

   50

Item 9B.

  

Other Information

   51
   PART III   

Item 10.

  

Directors, Executive Officers and Corporate Governance

   52
  

Directors, Executive Officers and Certain Other Officers

   52
  

Section 16 Reporting

   54
  

Code of Ethics

   54
  

Audit Committee

   54

Item 11.

  

Executive Compensation

   55
  

Compensation Discussion and Analysis

   55
  

Remuneration Committee Report

   61
  

Summary Compensation and Awards

   62
  

Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table

   63
  

Potential Payouts upon Termination or Change of Control

   68
  

Compensation of Directors

   72
  

Compensation Committee Interlocks and Insider Participation

   73

Item 12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

   73
  

Securities Authorized for Issuance under Equity Compensation Plans

   73
  

Security Ownership of Certain Beneficial Owners and Management

   75

Item 13.

  

Certain Relationships and Related Transactions, and Director Independence

   77

Item 14.

  

Principal Accountant Fees and Services

   78
   PART IV   

Item 15.

  

Exhibits, Financial Statement Schedules

   79

SIGNATURES

   83

 

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Cautionary Statement about Forward-Looking Statements

Some of the information included in this Annual Report on Form 10-K (“Form 10-K”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements give our current expectations or forecasts of future events. 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;

 

   

Demand 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 inherent to the natural gas and oil business;

 

   

Down hole 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;

 

   

Adverse weather conditions;

 

   

Availability and cost of material and equipment, such as drilling rigs and transportation pipelines;

 

   

The number of well locations to be drilled and the time frame in which they will be drilled;

 

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Delays in anticipated start-up dates;

 

   

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

 

   

Ability to find and retain skilled personnel;

 

   

Strength and financial resources of competitors;

 

   

Potential defects in title to our properties;

 

   

Federal and state regulatory developments and approvals;

 

   

Losses possible from pending or future litigation;

 

   

Environmental risks;

 

   

Worldwide political and 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 Form 10-K, as they speak only as of the date of this Form 10-K. 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 Form 10-K or to reflect the occurrence of unanticipated events. See the information under the heading “Item 1A—Risk Factors” 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.

 

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Unless otherwise indicated or required by the context, (i) “we”, “us”, and “our” refer to Gastar Exploration Ltd. and its subsidiaries and predecessors, (ii) all dollar amounts appearing in this Form 10-K are stated in United States (“U.S.”) dollars unless specifically noted in Canadian dollars (“CDN$”) or Australian dollars (“AUD$”), and (iii) all financial data included in this Form 10-K has been prepared in accordance with generally accepted accounting principles in the United States of America (“US GAAP”).

PART I

 

Item 1. Business

Overview

We are a Houston, Texas-based independent natural gas and oil company engaged in the exploration, development and production of natural gas and oil in the United States and Australia. Our domestic drilling activities are focused on exploiting our multi-year inventory of drilling locations in the deep Bossier sands and Knowles Limestone plays in the Hilltop area of East Texas and continuing exploitation of our coal bed methane, or “CBM”, assets in the Powder River Basin of Wyoming and Montana. Our operations in Australia are focused on the development of over 7.0 million gross (2.9 million net) acres of CBM rights in New South Wales and Victoria, Australia. We believe that our dual focus enables us to generate high initial production and long-lived producing wells with strong cash flow dynamics from our East Texas activities, while also providing us with significant reserve upside through the development of our Australian resource plays. We are a Canadian corporation incorporated in Alberta in 1987. We are publicly traded on the American Stock Exchange under the ticker symbol “GST” and on the Toronto Stock Exchange, or TSX, under the ticker symbol “YGA”.

Our Strategy

Continue Exploitation of Existing East Texas Assets.     Our East Texas portfolio includes 18 producing wells, which we anticipate will grow to 25 wells over the next 12 months. We have identified numerous Bossier and Knowles Limestone potential drilling opportunities on our current acreage position. These assets represent opportunities with strong return characteristics supportive of significant near-term production and cash flow growth.

Actively Manage Our Domestic Drilling Program.     We believe operating our core East Texas properties enables us to control the timing and cost of our drilling budget, as well as control operating costs and the marketing of our production. We have assembled an experienced team of operating professionals with specialized skills necessary to plan and execute the drilling and completion of the deep, high-temperature and high-pressure wells targeting the deep Bossier formation.

Exploit CBM Asset Base.     Our asset positions in southeastern Australia represent opportunities for significant reserve growth through our CBM drilling programs. Due to our pilot production success and the anticipated build up in the energy infrastructure in New South Wales, we anticipate continued participation with our operating partners in further pilot production, core-hole and other exploratory CBM activities. Initial commercial production from the Petroleum Exploration License “PEL” No. 238, or “PEL 238”, is anticipated in late 2008. We continue to evaluate our other CBM assets in the Powder River Basin in Wyoming and Montana for continued development drilling and re-completion activities that provide a source of stable production and cash flow.

Manage and Utilize Technological Expertise.     We believe that 3-D seismic analysis, enhanced natural gas recovery processes, horizontal drilling, and other advanced drilling technologies and production techniques are useful tools that improve drilling results and ultimately enhance production and returns. We believe that utilizing these technologies and production techniques in exploring for, developing and exploiting natural gas and oil properties will help us reduce drilling risks, lower finding costs and provide for more efficient production of natural gas and oil from our properties.

 

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Pursue Opportunistic Acquisitions.     We review opportunities to acquire producing properties, leasehold acreage and drilling prospects that are located in our core operating areas. We are seeking to acquire properties that provide a strategic fit with our existing activities or that represent new strategic areas that have a proved reserve base coupled with significant exploration or exploitation potential.

Natural Gas and Oil Activities

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

Hilltop Area, East Texas

Hilltop Area, East Texas .    The majority of our activities has been in the deep Bossier play in the Hilltop area, located in East Texas approximately midway between Dallas and Houston in Leon and Robertson Counties. This exploration play has attracted some of the largest and most active operators in the U.S. Wells in this area target multiple potentially productive natural gas formations and are typically characterized by high initial production, significant decline rates and long-lived reserves.

Our first successful operated well was spudded in 2003 and placed on production in September 2004. As of December 31, 2007, we had successfully completed 14 out of 15 deep Bossier wells and four out of four Knowles Limestone wells. During 2007, we drilled and successfully completed a total of five gross (3.0 net) Bossier wells and three gross (1.5 net) Knowles Limestone wells.

In May 2007, we sold a portion of our undeveloped natural gas and oil acreage in the Hilltop area of East Texas for approximately $66.5 million, net of transaction costs of approximately $1.2 million, resulting in a gain on sale of $38.5 million. We currently have a total of approximately 35,400 gross (16,300 net) acres in the Bossier play. In July 2007, we completed the processing of a 3-D seismic survey purchased earlier in the year. This survey covered all of our retained undeveloped acreage position and is being interpreted and used in the selection of our drilling locations. For 2008, we plan to drill up to three deep Bossier wells and four Knowles Limestone wells.

For the year ended December 31, 2007, net production from the Hilltop area averaged 13.0 MMcf per day. In January 2008, net production from the Hilltop area averaged approximately 20.2 MMcf per day.

Coalbed Methane—Powder River Basin, Wyoming and Montana

We own an approximate 40% average working interest in approximately 55,000 gross (21,900 net) acres in the Powder River Basin of Wyoming and Montana. The Powder River Basin has been an important natural gas producing area for nearly 100 years. Generally, CBM wells are shallow and less costly than conventional natural gas wells. Our primary areas of activity in the Powder River Basin are the Squaw Creek, Ring of Fire and adjacent fields, all of which are located north of Gillette, Wyoming in an active drilling area.

During 2006, we participated in the drilling of approximately 27 (12.5 net) CBM wells. As of December 31, 2007, we had an interest in 283 gross (125.2 net) productive CBM wells producing in the Basin. For the year ended December 31, 2007, our average net production from our CBM properties in the Powder River Basin was approximately 5.1 MMcf per day. We anticipate continuing our recompletion and drilling program in 2008. Our activity level will be influenced by regional natural gas prices, which remained lower than its historic prices relative to Gulf Coast Henry Hub natural gas prices during late 2007. Regional prices in early 2008 have rebounded to, or above, historic price levels.

 

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Coalbed Methane—PEL 238, Gunnedah Basin, New South Wales, Australia

We have a 35% interest in PEL 238, a CBM exploratory property covering approximately 2.2 million gross (786,000 net) acres, located in the Gunnedah Basin of New South Wales, approximately 250 miles northwest of Sydney, Australia, near the town of Narrabri. We believe that the strategic location of the properties and potential CBM reserves near the large natural gas markets in the Sydney-Newcastle-Wollongong area and the concession’s location relative to other developing gas markets should create a competitive marketing advantage for the natural gas reserves that may be developed on PEL 238.

Extensive coring of the coal on PEL 238 by the Australian government has provided a thorough understanding of the coal resources and potential CBM resource in place on our license. Two primary coal seams are found on the PEL 238 license, the Late Permian aged Hoskisson coal formation and the Early Permian aged Maules Creek coal formation.

During 2006, we participated with our joint venture partner and license operator, Eastern Star Gas Limited, in the drilling of eight new vertical coal seam natural gas wells on approximately 40-acre spacing in close proximity to an existing well within the Bohena Project Area of PEL 238 and one additional monitoring well. The results from the pilot production phase of the program have been positive, with the results confirming the high measured permeability of the coal and the presence of natural gas in the coal.

During 2007, we and our joint venture partner were approached by potential buyers with an interest in potentially contracting for up to 1 Tcf of natural gas from PEL 238. In March 2007, we announced that we and our joint venture partner had executed a Memorandum of Understanding (“MOU”) with Macquarie Generation, a New South Wales government-owned electricity generator, for the potential future supply of natural gas for its Bayswater power station. Macquarie Generation is Australia’s largest electricity producer and owns and operates two coal fired power stations in the Hunter Valley-Bayswater and Liddell. A long-term natural gas supply and purchase agreement with Macquarie Generation could include up to 500 Bcf to be delivered over a 15 to 20 year period commencing in late 2010, though there is no assurance that such an agreement will ultimately be reached or that such volumes will ultimately be produced from PEL 238. In addition, a potential gas supply and purchase agreement with Macquarie Generation would serve to underpin the development of the approximately 300 kilometers of pipeline infrastructure necessary to transport gas from the PEL 238 concession to Bayswater. An additional 150 kilometers of pipeline infrastructure would be required to access the natural gas markets of Sydney-Newcastle-Wollongong area.

In November 2007, we announced that we and our joint venture partner had entered into a second MOU with Babcock & Brown (“Babcock & Brown MOU”) to supply gas from the PEL 238 and PEL 433 concessions for use in the generation of electricity. The Babcock & Brown MOU envisions the supply of up to 30 Bcf per year of natural gas from the Gunnedah Gas Project to be delivered over multiple years for use in a gas fueled power station to be developed by Babcock & Brown in northern New South Wales, Australia commencing in late 2010. Natural gas sales under the anticipated agreements could be expanded to meet requirements for power station developments at other locations, though there is no assurance that such an agreement will ultimately be reached or that such volumes will ultimately be produced from the PEL 238 and PEL 433 concessions.

In September 2007, our independent petroleum engineers, Netherland Sewell & Associates, Inc. (“NSAI”), certified a quantity of proved and probable reserves under guidelines established by the Society of Petroleum Engineers (“SPE”), as a result of the success of one of our pilot production projects on PEL 238. These reserves, however, are not yet established as proved reserves under Securities and Exchange Commission, or SEC, guidelines nor can we assure that other unevaluated acreage will contain similar reserves.

Petroleum Assessment Lease 2, or PAL 2, was issued by the New South Wales Department of Primary Industries on October 30, 2007. PAL 2, in which Gastar holds a 35% interest, lies within PEL 238 and covers the existing Bohena Project Area of approximately 65,000 gross acres including the Bibblewindi and Bohena Production Pilots, with umbilical areas connecting to the Wilga Park Power Station. The assessment lease, which

 

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is intended for the area to be assessed for an eventual production lease, allows gas production from the two production pilots to ultimately be transported by a dedicated gas gathering system to the power station for electricity production and sale. We and our joint venture partner are in the permitting phase for the construction of the gathering system and pipeline, which is anticipated to be completed by late 2008.

During 2008, we, together with our joint venture partner intend to expand our pilot production drilling program on the PEL 238 concession. Through a planned development program in PEL 238 consisting of additional production pilot projects and core hole drilling, we are aiming to convert a portion of the substantial gross resource potential into additional certifiable proved and probable reserves as we move towards large-scale commercial production. We anticipate the certification of proved reserves and the growth of our probable reserves as necessary to support the development of infrastructure to service growing natural gas demand in New South Wales. Contracts and capital commitments for the construction of such infrastructure as well as gas sales or use contracts on PEL 238, will be necessary before we can recognize proved reserves under SEC guidelines.

The area on which PEL 238 is located is subject to a native title claim lodged in March 2007 by the Gomeroi Narrabri People (NSD437/07). See “Governmental Regulation-Australian Governmental Regulation-Native Title”.

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

PEL 433 is located south of PEL 238 where Gastar and our joint venture partner, Eastern Star Gas Limited, are developing the Gunnedah Basin Gas Project (Coal Seam Gas Joint Venture). Coal evaluation core-hole drilling completed during the 1970s and 1980s by the New South Wales government identified the distribution and thickness of the coal measures within a portion of PEL 433. The Hoskissons Coal Seam is believed to be approximately 4 to 6 meters thick and widely distributed within the eastern part of PEL 433. There has been no previous coal seam gas exploration and evaluation work in the area, and there is no information on gas content, gas composition or coal permeability.

In July 2007, we entered into a Farm-In Agreement with Eastern Star Gas Limited under which we have earned a 35% working interest in the PEL 433 and adjoining PEL 434 properties. Under the terms of the Farm-In Agreement, we paid the costs of a two core-hole program and the related costs of the evaluation of the coal reservoirs intersected by the core-holes.

The two corehole drilling program commenced during July 2007 and evaluated the coal seam gas potential of the Hoskissons Coal Seam within the Late Permian Black Jack Coal Measures. Additional coring may be undertaken on PEL 433 to provide additional data on coal depth, thickness, permeability, gas contents and composition.

The area believed to be the most prospective for coal seam gas within PEL 433 underlies and is in close proximity to the Central Ranges Natural Gas Pipeline that links Dubbo with Tamworth and joins with the larger Moomba-Sydney Gas Pipeline. This gas pipeline would enable gas sales within the region and potentially in Sydney and surrounding markets.

The area on which PEL 433 is located is subject to a native title claim lodged in June 2002 by the Tubba-Gah People (NSD6010/02). See “Governmental Regulation—Australian Governmental Regulation—Native Title”.

Coalbed Methane—EL 4416, Gippsland Basin, Victoria, Australia

We have a 75% interest in the CBM rights in EL 4416, an approximate 1.0 million gross (750,000 net) acre property covering a substantial part of the onshore portion of the Gippsland Basin of Victoria, Australia, located approximately 130 miles east of Melbourne. The EL 4416 property is well situated with three existing natural gas transmission lines running through the license area from productive offshore fields to a large natural gas

 

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processing facility and then to markets near Sydney, Melbourne and in Tasmania. The EL 4416 coal is classified as low-rank brown coal. The Victorian government has extensively evaluated the potential coal resources through detailed coal resource studies. Due to our large acreage position and the fact that this thick coal is present over a large percentage of the license area, the CBM resource potential is believed to be significant.

During 2006, we began initial long-term testing of the first of two wells completed on EL 4416. Before a pump failure, early water production had been significant, indicating permeability in the targeted coal seam. In late 2006, we pre-funded $6.5 million for a 10-well drilling program, which commenced drilling operations in late 2006. The program included the establishment of two “five-spot” pilots, one incorporating two existing wells and two wells designed to test for the presence and production potential of the coal at additional locations within the license area. In one of the two previously drilled wells, we have installed larger capacity pumps to facilitate de-watering operations.

Prior to the completion of the 10-well program mentioned above, Gastar and the operator of EL 4416, a subsidiary of GeoStar Corporation (“GeoStar”), became involved in a number of disputes concerning Gastar’s right to an assignment of its interest in EL 4416 and other jointly-owned properties. As a result, the operator has not provided Gastar with information concerning the results of the 10-well drilling program nor an accounting for the use of the funds provided for the drilling of the 10 CBM wells. While we believe we have good beneficial title to our interest in EL 4416, the subsidiary of GeoStar has not delivered to us a title assignment of our interest in a form to be recorded with Australian government officials. We have sent a letter to GeoStar demanding the arbitration of these issues. See Item 3, “Legal Proceedings—Arbitration and Litigation with GeoStar Corporation and Affiliates”.

No native title claims have been lodged at this time in relation to the area on which EL 4416 is located. See “Governmental Regulation—Australian Governmental Regulation—Native Title”.

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 natural gas from our properties with spot market contracts that vary with market forces on a monthly basis. While overall natural 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.

Australian natural gas markets and infrastructure exist and are viable markets; however, they are not as developed as the markets and infrastructure in the United States. Specifically, the PEL 238 concession is currently not served by any natural gas infrastructure. The initial gas market for PEL 238 natural gas is anticipated to be an electricity generation facility owned and operated by Eastern Star Gas Ltd. and located near the town of Narrabri, New South Wales, Australia. Although there currently is no pipeline from the existing and planned CBM project areas, we and our joint venture partner are in the permitting phase for the construction of the gathering system and pipeline, which is anticipated to be completed by late 2008.

 

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The longer term 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-Newcastle-Wollongong areas of New South Wales. Recent announcements of planned LNG facilities in southern Queensland are to be sourced from coalbed methane projects, which could potentially lead to the possibility of a portion of future PEL 238 production being sold to LNG export facilities. In March 2007, we announced that we had executed, along with our joint venture partner, a MOU with Macquarie Generation, a government-owned electricity generator in the state of New South Wales, Australia. The MOU sets the framework for negotiation of a potential long-term agreement to supply natural gas for Macquarie Generation’s Bayswater power station. In November 2007, we announced that we and our Joint venture partner had entered into a second MOU with Babcock & Brown (“Babcock & Brown MOU”) to supply gas from the PEL 238 and PEL 433 concessions for use in the generation of electricity. The Babcock & Brown MOU envisions the supply of up to 38 Bcf per year of natural gas from the Gunnedah Gas Project over multiple years for use in a gas fueled power station to be developed by Babcock & Brown in northern New South Wales, Australia commencing in late 2010. Natural gas sales under the anticipated agreements could be expanded to meet requirements for power station developments at other locations, though there is no assurance that such an agreement will ultimately be reached or that such volumes will ultimately be produced from the PEL 238 and PEL 433 concessions. In addition, a potential gas supply and purchase agreement with Macquarie Generation would serve to underpin the development of the approximately 300 kilometers of pipeline infrastructure necessary to transport gas from the PEL 238 concession to Bayswater. An additional 150 kilometers of pipeline infrastructure would be required to access the natural gas markets of Sydney-Newcastle-Wollongong area.

The area on which PEL 433 is located is subject to a native title claim lodged in June 2002 by the Tubba-Gah People (NSD6010/02). See “Governmental Regulation – Australian Governmental Regulation-Native Title”.

The EL 4416 license in the Gippsland Basin of Victoria, the site of recent pilot CBM drilling and planned production testing, is served by three existing natural gas transmission pipelines. The existing pipelines have capacity to transport natural gas from the EL 4416 license to markets in the area of Sydney, Melbourne and Tasmania. If our efforts result in commercial CBM production from this license, minimal infrastructure expenditures would be necessary to connect to existing pipelines. Victoria has both a spot market for natural gas and a developed market for contract sales of natural gas.

Our very limited oil production in Texas and the Appalachian Basin 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.

In March 2008, we entered into formal agreements with ETC Texas Pipeline, Ltd. (“ETC”) for the gathering, treating, purchase and transportation of our natural gas production from the Hilltop area of East Texas. These agreements are effective September 1, 2007 and have a term of 10 years. ETC currently provides us 50 MMcfd of treating capacity and 120 MMcfd of gathering capacity. We have the right to request ETC build, at their cost, up to 150 MMcfd of treating and gathering capacity during the term of the agreement, provided that our production equals 85% of the then existing treating and gathering capacity for a 30 day period. We may at any time elect to have our treating and gathering capacity increased subject to cost indemnifications to ETC. Additional treating and gathering capacity requests must be in at least 25 MMcfd and 5 MMcfd increments, respectively. In addition, we must furnish to ETC information that reasonably demonstrates that our projected production for the five years after expansion is sufficient to warrant the costs to create the expanded treating and gathering capacity. The incremental volume increases in treating and gathering capacity shall be subject to marginal increases in treating fees. Pursuant to the agreements, we have access up to 150 MMcfd of firm transportation on ETC’s system or the pipelines of its affiliates or subsidiaries from the tailgate of the treating facility to Katy Hub. We have the option to sell and ETC has the obligation to buy, up to 150 MMcfd of our Hilltop production at delivery points upstream of ETC’s gathering and treating facilities. We do not have an obligation to deliver to ETC volumes in excess of 150 MMcfd, but should ETC elect to purchase such excess volumes, purchases will be subject to the treating and gathering expansion terms set forth in the agreements.

 

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During 2007, ETC and Enserco Energy, Inc. (“Enserco”) accounted for 78% and 20% of our natural gas and oil revenues, respectively. During 2006, sales to ETC and Enserco accounted for 63% and 25% of our natural gas and oil revenues, respectively. During 2005, ETC and Enserco accounted for 65% and 26%, respectively, of our natural gas and oil revenues. Although ETC is the major natural gas purchaser and transporter in the area of our deep Bossier play and only limited natural gas purchaser and transporter alternatives are currently available in this area, management believes that other natural gas purchasers and transporters could ultimately be located and would minimize any long-term material adverse impact on our financial condition or results of operations. Management believes that the loss of Enserco in the Powder River Basin would not have a long-term material adverse impact on our financial position or results of operations, as there are numerous other purchasers operating in the Powder River Basin.

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, many of whom 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.

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 smaller and have a more limited operating history than most of our competitors 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 providing the manpower to operate them and provide related services.

Governmental Regulation

In addition to the environmental regulations discussed below, our natural gas and oil exploration, production and related operations are subject to extensive rules and regulations promulgated in the United States and Australia. 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; ongoing obligations for licensing; 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 prospect or acreage.

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

 

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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. Governmental 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, or 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 natural gas produced by us and the revenues received by us for sales of such natural gas. FERC requires interstate pipelines to provide open-access transportation on a non-discriminatory basis for all natural gas shippers. 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, 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 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 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 natural gas and oil industry. Many departments and agencies, both federal and state are authorized by statute to issue, and have issued, rules and regulations binding on the natural gas and oil industry and its individual participants. The failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the natural gas and oil 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 natural gas and oil 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. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of the natural gas and oil properties; the establishment of maximum rates of production from natural gas

 

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and oil wells; the spacing of wells; and the plugging and abandonment of wells and removal of related production equipment. These regulations can limit the amount of the natural gas and oil 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 Governmental Regulation

Commonwealth and State Laws and Regulations .    The regulation of the activities of participants in 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, petroleum industry licensing, foreign investment, cultural heritage and native title restrictions on accessing resources in Australia. These regulations are in addition to any state level regulations.

Foreign Investment Regulation.     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 Treasurer 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, investment in or formation of a new business, or acquisition of urban land will require review and approval under the commonwealth foreign investment policy and regulations.

Native Title.     In a landmark Australian High Court decision in 1992, it was recognized that the native title to land of Indigenous Australians survived the acquisition of sovereignty by the British Crown. However native title to any particular area will only survive to the present if it has not been extinguished subsequently. Native title may be extinguished by the action of government, such as the creation of an interest that is inconsistent with native title. In particular, the grant of the right to exclusive possession through freehold title or a lease will wholly extinguish native title. Native title may also be extinguished if the connection between the land and the group of Aboriginal people claiming native title has been lost. The Native Title Act 1993 (Cth) 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 how dealings affecting native title can be conducted in the future. Native title claims by Aboriginal groups can cover existing and potential natural gas and oil exploration and development areas. If we apply to the relevant state or territory for an onshore exploration permit or production license over Crown land or “Aboriginal” land which has a registered native title claimant or a registered native title holder, we will have to go through a mandatory negotiation process, followed by an arbitration conducted by the National Native Title Tribunal if no agreement can be reached through negotiation. The results of the negotiation may impose significant financial obligations on us. Each application for an exploration permit, production license or a pipeline license must be examined individually in order to determine the existence of native title claims or determinations. To validly affect native title, permits and licenses must be granted in compliance with the Native Title Act 1993 (Cth) .

Australian Petroleum Regulation and Gas Markets.     All petroleum tenements in which we hold an interest are subject to specific licensing regulation in the relevant states. Each exploration permit or production license will (depending on the nature of the license and the state in which the project is located) be issued subject to various obligations. These may include obligations as to expenditure, payment of rent, consultation with occupiers and rehabilitation. These obligations must be met to maintain the good standing of the tenement. Licenses may be cancelled or revoked for non compliance. In Australia, the ownership of minerals (including petroleum) is vested in the government and ownership only passes to the license holder once the relevant mineral is extracted. We are required to pay Government royalties of 10% of the wellhead value of petroleum extracted. Several statutory mechanisms regulate access rights to a range of infrastructure in Australia including gas

 

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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 on our operations but believe it could benefit us.

Environmental Regulation

Our U.S. natural gas and oil exploration and production operations and similar operations that we do not operate but in which we own a working interest are subject to significant federal, state and local environmental laws and regulations governing environmental protection as well as the discharge of substances 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 may result in the issuance of injunctions limiting or prohibiting operations, as well as administrative, civil and even criminal penalties. The effects of these laws and regulations, as well as the assessment of 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 and regulations or the modification or more stringent enforcement of existing laws and 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 significant resources in order to satisfy existing applicable environmental laws and regulations. However, there is no assurance that costs to comply with existing, and any new environmental laws and regulations in the future will not be 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 Regulations

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

 

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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 transported, 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 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. In the past, proposals have been made to amend RCRA to rescind this exemption. Repeal or modification of the exception or similar exemptions in state law could increase the amount of hazardous waste we are required to manage and dispose of and could cause us to incur increased operating cost, which could have a significant impact on us as well as the natural gas and oil 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 or recycling. 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.

 

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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. Nonetheless, in connection with CBM production in the Powder River Basin, a concern common to many operators in the Basin is the potential for opposition by individuals or groups to the issuance of a permit for the discharge or disposal of water generated by production activities. Such opposition could result in delays, limitations or denials with respect to environmental or other approvals necessary to develop our acreage in the Powder River Basin, which could adversely affect our financial condition or results of operations.

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 CAA 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, there is no assurance in the future, we will not be required to incur capital expenditures in connection with maintaining or obtaining operating permits and approvals addressing air emission-related issues.

Our CBM production operations involve the use of gas-fired compressors to produce or transport gas that is produced. Emissions of combustible by-products from compressors at one location may be large 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 that have been 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 the 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 response to recent studies suggesting that emissions of certain gases including carbon dioxide, may be contributing to warming of the Earth’s atmosphere, many foreign nations have agreed to limit emissions of these gases, generally referred to as “greenhouse gases”, pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol”. Although the United States is not participating in the Kyoto Protocol, the current session of Congress is considering climate change legislation, with multiple bills

 

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having already been introduced in the Senate that propose to restrict greenhouse gas emissions. One bill recently approved by the U.S. Senate Environment and Public Works Committee, known as the Lieberman-Warner Climate Security Act or S.2191, would require a 70% reduction in emissions of greenhouse gases from sources within the United States between 2012 and 2050. The Lieberman-Warner bill proposes a “cap and trade” scheme of regulation of greenhouse gas emissions or a ban on emissions above a defined reducing annual cap. Covered parties will be authorized to emit greenhouse emissions through the acquisition and subsequent surrender of emission allowances that may be traded or acquired on the open market. A vote on this bill by the full Senate is expected to occur before mid-year 2008. In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs require either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall greenhouse gas emission reduction goal is achieved. Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of fuels (such as natural gas or oil) we produce. Although we would not be impacted to a greater degree than other similarly situated producers of natural gas and oil, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the natural gas and oil we produce.

Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA , the EPA may be required to regulate carbon dioxide and other greenhouse gas emissions from mobile sources, such as cars and trucks even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The EPA has indicated that it will issue a rulemaking notice to address carbon dioxide and other greenhouse gas emissions from vehicles and automobile fuels, although the date for issuance of this notice has not been finalized. The Supreme Court’s holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New federal or state restrictions on emissions of carbon dioxide that may be imposed in areas of the United States in which we conduct business could also adversely affect our cost of doing business and demand for the natural gas and oil we produce.

Finally, legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security, or DHS, and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations and the operations of the natural gas and oil industry in general may be subject to such laws and regulations. The federal Department of Homeland Security Appropriations Act of 2007 required the DHS to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including natural gas and oil facilities that are deemed to present “high levels of security risk”. The DHS issued an interim final rule, known as the Chemical Facility Anti-Terrorism Standards Interim Final Rule, in April 2007 regarding risk-based performance standards to be attained pursuant to the Act and, on November 20, 2007, further issued an Appendix A to the interim rule that establish chemicals of interest and their respective threshold quantities that trigger compliance with this rule. Facilities that possess the threshold quantities of chemicals of interest must submit to an initial screening process for DHS to determine if they present a high level of security risk. Facilities that are deemed to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans and comply with other regulatory requirements including those regarding inspections, audits, recordkeeping and protection of Chemical-terrorism Vulnerability Information. We have not yet determined the extent to which our facilities are subject to the interim rules or the associated costs to comply, but it is possible that such costs could be substantial.

 

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Australian Environmental Regulations

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 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.

Australia ratified the Kyoto Protocol on December 3, 2007, and officially committed to meeting its Kyoto Protocol target. Australia set a target to reduce greenhouse gas emissions by 60% on 2000 levels by 2050 and committed to actively participate in negotiations working towards a post 2012 agreement involving developed and developing countries. Australia has introduced a National Greenhouse and Energy Reporting Act 2007 , which establishes a single national system for reporting greenhouse gas emissions, abatement actions and energy consumption and production by corporations from July 1, 2008. Data reported through the system will underpin the Australian Emissions Trading Scheme, or AETS, which is to be introduced by 2010. The consultation stage and detailed design of the AETS is to be finalized by the end of 2008. The government has made it clear that it plans to introduce a “cap and trade scheme” in which total emissions are capped, permits allocated up to the cap and trading allowed to let the market find the cheapest way to meet any necessary emission reductions. As the details of the AETS are not yet finalized, we are unable at this stage to assess the likely impact of the AETS on our operations in Australia.

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 time to the existing approval process but its effect on a project will depend on the significance of the impact identified. 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 and planning issues are 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. Generally speaking, onshore natural gas and oil projects in New South Wales and Victoria require an environmental approval from the state (and sometimes commonwealth) government, land use planning approval from local government and an approval under the relevant petroleum regime (as referred to above). Legislation provides for the integrated assessment of these issues. The environmental regulators in both New South Wales and Victoria have the ability to require a project operator to prepare and implement a plan to improve the environmental performance of a project and may also amend the conditions on an existing environmental approval. As such, the environmental regulation of a project may not be assumed to remain static following approval and may become more onerous over time. 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. Approvals will usually include terms which require remediation and reinstatement obligations for the site during the course of operations and following closure of the project.

 

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Australian laws and regulations protecting archeological relics, cultural, 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 replacement, as well as liability in respect of damage. In particular, indigenous cultural heritage protection laws are becoming increasingly stringent and in many states and the Northern Territory the specialist indigenous heritage protection laws require a proponent to negotiate directly with indigenous groups with respect to a major project.

Industry Segment and Geographic Information

We operate in one industry segment, which is the exploration, development and production of natural gas and oil. Our operational activities are conducted in the United States and Australia with only the United States currently having revenue generating operating results.

Employees

As of March 10, 2008, we had 23 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, regulatory reporting, 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. Our employees do not belong to a union or have a collective bargaining organization. Management considers its relationship with employees to be good.

Corporate Offices

We lease our corporate offices at 1331 Lamar Street, Suite 1080, Houston, Texas 77010. Our office space covers 9,332 square feet at a monthly rental of $17,100 through October 2010. We maintained an office in Miami, Florida (our Chief Executive Officer’s city of residence) through April 2007 at a monthly rental of $2,700 per month.

Internet Website Access

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange are made available free of charge on our internet website at www.gastar.com as soon as reasonably practicable after we have electronically filed the material with, or furnished it to, the SEC. The public may read and copy any materials we have filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet website that contains our reports, proxy and information statements and our other SEC filings. The address of that site is www.sec.gov . Information is also available at www.sedar.com for our filings required by Canadian securities regulators and the Toronto Stock Exchange. None of the information on our internet website or filed by us on www.sedar.com should be considered incorporated into, or considered a part of, this report.

We also make available free of charge on our internet website at www.gastar.com our:

 

   

Code of Ethics;

 

   

Terms of Reference of our Audit Committee;

 

   

Terms of Reference of our Governance Committee:

 

   

Terms of Reference of our Remuneration Committee;

 

   

Terms of Reference of our Nominating Committee; and

 

   

Whistleblower Procedure.

 

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Item 1A. Risk Factors

Risk Factors Related to Our Business

In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following material risk factors associated with our business and our common shares when evaluating Gastar. An investment in Gastar is subject to risks inherent in our business. The trading price of our common shares 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.

Natural gas and oil prices are volatile and a decline in natural gas and oil prices can significantly affect our financial condition and results of operations.

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 have a material adverse 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. Natural gas and oil prices will likely 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:

 

   

The domestic and foreign supply of natural gas and oil;

 

   

Overall economic conditions;

 

   

Weather conditions;

 

   

Political conditions in the Middle East and other oil producing regions, such as Venezuela;

 

   

Domestic and foreign governmental regulations;

 

   

The level of consumer product demand; and

 

   

The price and availability of alternative fuels.

Our success is influenced by 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 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. As of December 31, 2007, approximately 72% of our production is priced based on the Katy Hub (“Katy”) basis point, and the remainder is priced on the CIG basis point. Recently, natural gas prices on CIG have been extremely volatile, and spot sales of natural gas in the region traded at prices substantially below historic levels, when compared to prices in other primary natural gas sales points in the country. This has been attributed primarily to limitations in available pipeline capacity for natural gas deliveries out of the Rocky Mountain area. In 2007, spot prices for CIG Rocky Mountains on occasion dipped to less than $1.00 per MMBtu. While this volatility currently has been alleviated by completion of a major pipeline system in January 2008, this relief may be offset over time by the expected increase in supply of natural gas available in the Rocky Mountains. At December 31, 2007, the Katy hub basis traded at approximately par to Henry Hub, and CIG hub basis traded at approximately 11% less then Henry Hub. Low natural gas prices in any or all of the areas where we operate would negatively impact our financial condition and results of operations.

 

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In Victoria and New South Wales the wholesale price for gas is determined by contract negotiations and is not related to a “hub” or “spot market” price. Prospective natural gas sales related to our pilot CBM project in New South Wales will be dependent on electricity prices in the area since the natural gas is being dedicated initially as fuel for an electric generation facility.

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 successful exploration and development activities and/or acquire properties containing proved reserves. 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, which could have a material adverse effect on our financial condition, future cash flows and the results of operations.

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:

 

   

Unexpected drilling conditions;

 

   

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

 

   

Pressure or irregularities in formations;

 

   

Equipment failures or accidents;

 

   

Adverse weather conditions;

 

   

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

 

   

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 have a material adverse affect our financial condition, 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.

We have incurred significant net losses since our inception and may incur additional significant net losses in the future.

We have not been profitable since we started our business. We incurred net losses of $30.5 million, $84.8 million and $25.7 million for the years ended December 31, 2007, 2006 and 2005, respectively. Our capital has been employed in an increasingly expanding natural gas and oil exploration and development program with the focus on finding significant natural gas and oil reserves and producing from them over the long-term rather than focusing on achieving immediate net income. The uncertainties described in this section may impede our ability to ultimately find, develop and exploit natural gas and oil reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future.

 

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We have a substantial amount of debt, which may adversely affect our cash flow and our ability to operate our business, to remain in compliance with debt covenants and make payments on our debt.

As December 31, 2007, we have had total debt of $133.3 million of which $100.0 million consisted of the 12  3 / 4 % senior secured notes due 2012 (“12  3 / 4 % Senior Secured Notes”), $30.0 million consisted of convertible senior debentures due 2009 and $3.3 million consisted of subordinated unsecured notes due 2009. Our level of indebtedness affects our operations in several ways, including the following:

 

   

We may have difficulty borrowing money in the future for acquisitions, capital expenditures or to meet our operating expenses or other general corporate obligations;

 

   

We will need to use a substantial portion of our cash flows to pay principal and interest on our debt, which will reduce the amount of money we have for operations, working capital, capital expenditures, expansion, acquisitions or general corporate or other business activities;

 

   

We have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms;

 

   

We may be more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially declines in natural gas and oil prices; and

 

   

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

 

   

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

We may incur substantially more debt, which may intensify the risks described above, including our ability to service our indebtedness.

We may to incur substantially more debt in the future. Although the indenture governing the 12  3 / 4 % Senior Secured Notes and our Revolving Credit Facility contain restrictions on our incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial.

Disputes have arisen between GeoStar and us in connection with the POA, general operating and administrative activity, and purchase price adjustments relating to certain Texas properties.

Over the past six years, we entered into various transactions or agreements with GeoStar, one of our former majority shareholders and an affiliate of our former Chairman of the Board. In 2001, we entered into a Participation and Operating Agreement (the “POA”) with GeoStar that governed certain property acquisition, exploration and development activities of GeoStar and us. Various disputes have arisen, primarily over the past year, in connection with the POA and general operating and administrative activity between GeoStar and us. GeoStar claims that we have breached alleged agreements to reimburse it for various payments and services allegedly performed by GeoStar and its personnel and paid on our behalf by GeoStar. GeoStar claims that the amounts of the payments and the value of the services exceed $17.0 million. GeoStar alternatively alleges that if there was no contract covering those payments and services, it allegedly is entitled to reimbursement on equitable principles. We have also requested that GeoStar’s Australian subsidiary provide a record title assignment of our 75% beneficial interests in EL 4416, the exploration license in the Gippsland Basin property in Victoria, Australia. GeoStar seeks a declaration that we do not own rights in EL 4416. Although we strongly contend that these additional GeoStar charges are without merit and that GeoStar owes us approximately $3.7 million at December 31, 2007, we may not prevail. Payment to GeoStar of the amounts asserted would have a material adverse effect on our financial condition, future cash flows and the result of operations.

 

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In addition, a dispute has arisen regarding the Purchase and Sale Agreements (the “PSAs”) between GeoStar and the Company relating to certain East Texas properties acquired by us in 2005. The PSAs contain a provision whereby a “Look Back Payment” is calculated based in part on changes in proved and probable reserves attributable to certain of our East Texas leasehold interests over certain periods of time. Payments to GeoStar under the PSAs, if any, are to be effected through the issuance of our common shares. On November 7, 2007, GeoStar submitted a reserve report to us that reports substantially greater reserve estimates than the estimates we have obtained. GeoStar has also asserted that the Look Back analysis should be based on changes in reserves attributable to the entirety, or 8/8ths, of the leasehold interests with respect to the East Texas properties, rather than on changes in reserves attributable to GeoStar’s net revenue interest in those properties as of the effectiveness of the PSAs, as we believe. We vigorously dispute that GeoStar’s reserves report complies with the requirements of the PSAs and vigorously dispute GeoStar’s contention as to the portion of reserves subject to the Look Back analysis. However, if GeoStar were to present both of these current assertions in litigation and obtain an outcome adverse to the Company on both issues, we could be required to issue a number of shares to GeoStar sufficient to cause a change in control of the ownership of Gastar.

In 2007, the Company recorded a $1.4 million litigation settlement expense accrual related to a proposed settlement with GeoStar regarding the various GeoStar arbitration and litigation matters. The settlement proposal was never finalized. Information about our legal proceedings is set forth in Note 16—Commitments and Contingencies—Litigation to our consolidated financial statements, which begin on Page F-1.

Deficiencies of title to our leased interests could significantly affect our financial condition.

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 drilling an exploration well, the operator of the well will typically obtain a preliminary title review of the drillsite lease 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. 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, which could affect our financial condition and results of operations. Information about our legal proceedings is set forth in Note 16—Commitments and Contingencies—Litigation to our consolidated financial statements, which begin on page F-1.

A dispute between third parties affecting the ownership of undivided interests in certain East Texas oil and gas leases that we sold in 2005 may make it difficult for us, as operator of those leases, to obtain funds for some of our planned joint drilling operations until the dispute is resolved.

In 2005, we sold Chesapeake Energy Corporation a one-third undivided interest in various oil and gas leases, located in Leon and Robertson Counties, Texas together with shares of our common stock. Navasota Resources, L.P. filed a lawsuit against us and Chesapeake asserting a preferential right to purchase the undivided leasehold interest under an operating agreement. While this issue was resolved by the trial court in favor of Chesapeake, an appeals court has recently reversed and rendered judgment favoring Navasota’s right to acquire the undivided interest. Chesapeake and the Company filed a motion for rehearing and, if unsuccessful, may consider an appeal to the Texas Supreme Court. While ownership of this undivided leasehold interest remains unresolved, Chesapeake and Navasota are disputing responsibility for paying the proportionate share of joint capital and operating costs relating to this interest or approving authorizations for future joint drilling expenditures. Delays in determining ultimate ownership of this interest could lead to the Company paying a disproportionate share of costs at its own risk or result in a delay in drilling of wells planned on this acreage in East Texas, which could have a material adverse effect on our financial condition, future cash flows and the results of operations.

 

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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:

 

   

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

 

   

The assumed effects of regulations by governmental agencies;

 

   

Assumptions concerning future prices;

 

   

Assumptions concerning future operating costs;

 

   

Assumptions concerning severance and excise taxes; and

 

   

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.

You should not consider the present values of estimated future net cash flows referred to in this Form 10-K 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:

 

   

The amount and timing of actual production;

 

   

Supply and demand for natural gas or oil;

 

   

Actual prices received for natural gas in the future being different than those used in the estimate;

 

   

Curtailments or increases in consumption of natural gas or oil;

 

   

Changes in governmental regulations or taxation; and

 

   

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

In this Form 10-K, 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.

 

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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, write downs in the future may 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.

A majority of our proved reserves are classified as proved developed non-producing and proved undeveloped and may ultimately prove to be less than estimated.

At December 31, 2007, approximately 60% of our total proved reserves were classified as proved developed non-producing and proved undeveloped. It will take substantial capital to recomplete or drill our non-producing and undeveloped locations. Our estimate of proved reserves at December 31, 2007 assumes that we will spend significant development capital expenditures to develop these reserves, including an estimated $39.1 million and $9.5 million in 2008 and 2009, respectively. Further, our drilling efforts may be delayed or unsuccessful, and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and the results of operations.

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 could intensify with 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 results of operations. While we entered into contracts for the services of drilling rigs in North America and Australia, we may not be successful in doing so in the future. 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 have a material adverse effect on our financial condition, future cash flows and the results of operations.

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.

 

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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 obligations, and the issuance of orders enjoining or limiting future operations, any of which could have a material adverse affect on our financial condition. Legal requirements are sometimes unclear or subject to reinterpretation and may be 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, existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations may have a material adverse effect on our financial condition, future cash flows and the results of operations.

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. Joint and several, strict liability may be incurred without regard to fault or the legality of the original conduct under certain of these laws and regulations for the remediation of contaminated areas. Private parties, including the owners of properties located near our storage facilities or through which our pipeline systems pass, also may have the right to pursue legal actions to enforce compliance, as well as seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. Consequently, the discharge or release of natural gas, oil or other substances into the air, soil or water, even by predecessor operators, could subject us to liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, property and natural resource 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.

Native title, which is based on the traditional laws of Aboriginal groups, was recognized in Australia in 1992. Since 1994 there has been a process under the Native Title Act 1993 (Cth) through which indigenous groups claiming to hold native title can have their title formally recognized. Because native title, by definition, has existed uninterrupted since white settlement of Australia, claims with a reasonable prospect of success are “registered” and registered claimants have certain rights to participate in government land use decisions affecting land to which they may hold native title. Through the claims process, there are some areas in Australia where native title is now formally recognized. However, in New South Wales and Victoria, where we have our Australian operations, most native title claims are yet to be resolved.

Native title can and has been extinguished across much of Australia and cannot be revived. Native title may be wholly extinguished in relation to particular areas of land by a grant of an inconsistent title, such as freehold or a lease conferring exclusive possession. Where this has occurred it is possible to determine that native title has been extinguished irrespective of the formal resolution of a claim. Native title has no effect in relation to land use in such areas. Native title is also extinguished where the traditional Aboriginal owners have lost their traditional links to the land. This can usually only be determined through the claim resolution process.

 

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Native title can impact our Australian operations in two important ways:

 

   

Validity of interests: Where we are seeking to obtain an authority to prospect, develop resources or construct a pipeline over land subject to a registered native title claim or determination, in respect of which prior extinguishment cannot be demonstrated, it is necessary to follow the processes contained in the Commonwealth native title the Native Title Act 1993 (Cth) to ensure validity of the authority insofar as it affects native title.

 

   

Costs and delays associated with procedural rights of registered native title claimants/holders when seeking government authorities: Under the Native Title Act 1993 (Cth) , registered native title claimants or holders (native title parties) have certain procedural rights in relation to the grant of authorities by the state government in respect of land to which they may or do hold native title. We may be required to attempt to reach agreement with any native title parties as to the terms on which they will agree to the grant of the authority we seek. Such an agreement may include immediate payments, revenue sharing, or both. Payments are likely to apply even before the claim is formally resolved. An agreement may also restrict the area where prospecting or development can occur in order to ensure that areas of cultural heritage significance are preserved. Reaching agreement with a native title party can be costly and cause delay. Generally, the costs associated with the grant of pipeline licenses are less than those for production approvals. It is possible to request the National Native Title Tribunal to arbitrate a dispute regarding the terms on which a prospecting or production authority can be granted, if there has been no resolution after six months. Other processes are available for resolution of disputes regarding pipeline licensing approvals according to state laws.

There are registered native title claims in the Gunnedah Basin in New South Wales affecting PEL 238 and 433. EL 4416 in the Gippsland Basin in Victoria is not presently subject to a native title claim. However, a claim may be lodged which affects this property in the future.

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.

 

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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. 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.

Approximately 79% of our revenues for the year ended December 31, 2007 was from the production of wells located in our deep Bossier play in East Texas. Any disruption in production or our ability to process and sell our natural gas production from this area would have a material adverse effect on our results of operations.

Production of the natural gas in East Texas could unexpectedly be disrupted or curtailed due to reservoir or mechanical problems. Our natural gas produced from this area contains levels of carbon dioxide and hydrogen sulfide that are above levels accepted by gas purchasers. This production must be treated by the purchaser. A majority of our East Texas production is processed by the purchaser. If the purchaser’s facilities ceased to operate, were destroyed or otherwise needed replacement, it could require 60 to 90 days to replace or repair these facilities. A 60 to 90 day curtailment of our East Texas production could reduce current revenues by an estimated $5.0 to $7.5 million, with a corresponding reduction in our cash flow.

The CBM which we produce in the Powder River Basin may be drained by offsetting production wells.

Our drilling locations in the Powder River Basin are spaced primarily using 80-acre spacing. Producing wells located on the 80-acre spacing units contiguous with our drilling locations may drain the acreage underlying our wells. If a substantial number of productive wells are drilled on spacing units adjacent to our properties, they may decrease our revenue and could have an adverse impact on the economically recoverable reserves of our properties that are susceptible to such drainage.

Our Powder River Basin CBM wells typically have a shorter reserve life and lower rates of production than conventional natural gas wells, which may adversely affect our profitability during periods of low natural gas prices.

The shallow coals from which we produce CBM in the Powder River Basin typically have a two to six year reserve life and have lower total reserves and produce at lower rates than most conventional natural gas wells. We depend on drilling a large number of wells each year to replace production and reserves in the Powder River Basin and to distribute operational expenses over a larger number of wells. A decline in natural gas prices could make certain wells uneconomical because production rates are lower on an individual well basis and may be insufficient to cover operational costs.

There are a limited number of natural gas purchasers and transporters in the Hilltop area of our deep Bossier play in East Texas. The loss of our current purchaser and transporter and an inability to locate another purchaser and transporter would have a material adverse effect on our financial condition and results of operations.

There are a limited number of natural gas transporters in the Hilltop area in East Texas. For the year ended December 31, 2007, ETC accounted for substantially all of our revenues from this area. If ETC were to cease purchasing and transporting our natural gas and we were unable to contract with another transporter, it would have a material adverse effect on our financial condition, future cash flows and the results of operations.

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

 

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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 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, our interests may not receive favorable rulings from any state agency, or some future occurrence may drastically alter our ability to enter into contracts or deliver natural gas to the market.

In recent years pipeline capacity for natural gas deliveries out of the Rocky Mountain area has been, at times, significantly constrained resulting in an oversupply and creating substantial discounts on spot natural gas prices received for regional production. This has had a substantial impact on the prices received for natural gas production from Wyoming and Montana, as compared to Gulf Coast natural gas prices. While a recently completed interstate pipeline currently has alleviated the problem by providing access to the Midwest interstate pipelines and markets, the relief may be offset over time by the expected increase in supply of natural gas available in the Rocky Mountains.

Australian natural gas markets and transmission infrastructure exists but they are not as developed or interconnected as the markets and infrastructure in the United States. Specifically, the PEL 238 concession is currently not served by natural gas transmission infrastructure. The initial gas market for PEL 238 natural gas is anticipated to be an electricity generation facility located near the town of Narrabri, New South Wales. A short transmission pipeline is required to be built to serve this initial market. Access to a larger electricity facility will require construction of a pipeline of approximately 300 kilometers to reach PEL 238 with an additional 150 kilometers of pipeline infrastructure required to access the natural gas markets in the Sydney-Newcastle-Wollongong markets. The capital costs for these projects, if deemed feasible, would be substantial in order to realize the value of any identified reserves and construction would require significant amounts of time.

The EL 4416 license in the Gippsland Basin of Victoria, the site of recent pilot CBM drilling and planned production testing, is served by three existing natural gas transmission pipelines. At the time production commences, the existing pipelines may have constraints in the capacity available to transport natural gas from the EL 4416 license to markets in the area of Sydney, Melbourne and Tasmania.

Our exploration rights in Australia are subject to renewal at the discretion of the government.

Coal bed methane exploration in Victoria is conducted under an exploration license granted under the Mineral Resources (Sustainable Development) Act 1990 (Victoria) which is granted at the discretion of the Minister for Primary Industries. Each exploration license requires the expenditure of a set amount of exploration costs and is generally subject to renewal for five years after the initial term of five years. On renewal of an exploration license, the Minister may require reduction of the area to which the exploration license applies.

Coal bed methane exploration in New South Wales is conducted under a Petroleum Exploration License (“PEL”) granted under the Petroleum (Onshore) Act 1991 (NSW), which is granted at the discretion of the Minister. Each PEL requires the expenditure of a set amount of exploration costs and is generally subject to renewal a term of up to six years after the initial term of up to six years. On renewal of a PEL, the Minister may require reduction of the area to which the PEL applies.

We cannot assure that our exploration licenses or PELs will be renewed. Non-renewal or loss of an exploration licenses or PELs could adversely affect our exploration and development plans, results of operations, financial condition or cash flows.

 

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Competition in the natural gas and oil industry is intense. We are smaller and have less operating history than many of our competitors, and increased competitive pressure could adversely affect our results of operations.

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. Increased competitive pressure could have a material adverse effect on our financial condition, future cash flows and the results of operations.

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;

 

   

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

 

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associated costs could have a material adverse affect on 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, many 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. If one or more of the technologies that we currently use or may implement in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, it could have a material adverse effect on our financial condition, future cash flows and the results of operations.

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, 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 and maximize our business plan is dependent on our ability to obtain adequate financing.

Our 2008 capital expenditures under our current business plan are estimated to total approximately $65.4 million, of which $43.4 million is estimated to be spent on unconventional natural gas and oil exploration and development operations in East Texas, $7.4 million is estimated to be spent on CBM projects and additional projects in the United States and $14.6 million is estimated to be spent on CBM projects in Australia. 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 will require additional financing to fund our planned growth and scheduled debt maturities beyond the next 12 months. 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 credit agreements will 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.

Disputes with GeoStar may make it difficult for us to raise capital through the sale of equity.

The 2005 Purchase and Sale Agreements, or 2005 PSAs, between GeoStar and the Company relating to certain East Texas properties acquired by the Company contain a “look back” contingent payment provision that is the subject of claims in certain litigation matters with GeoStar. The 2005 PSAs sets forth a formula by which

 

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the amount of the look back payment is based in large part upon estimates of proved and probable reserves attributable to the East Texas properties as of June 30 of 2006 and 2007. Under the 2005 PSAs, the look back payment is to be settled by the issuance of our common shares. GeoStar asserts that, under its calculations, it is entitled to a look back payment of approximately 1.7 billion shares of our common stock, which if issued would constitute approximately 89% of our outstanding common equity. The Company strongly disputes GeoStar’s assertions. While these litigation matters remain pending, it will be difficult for us to raise equity capital through the sale of our common stock to fund future operations and capital needs. Information about our legal proceedings with GeoStar is set forth under the caption “Litigation—Arbitration and Litigation with GeoStar and its Affiliates” in Note 16—Commitments and Contingencies to our consolidated financial statements, which begin on page F-1.

Hedging of our production may result in losses or prevent us from benefiting to the fullest extent possible from increases in prices for natural gas and oil.

In September 2007, we commenced hedging our natural gas production utilizing costless collars. Although these hedges may partially protect us from by declines in natural gas prices, the use of these arrangements may limit our ability to benefit from significant increases in the prices of natural gas.

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. Particularly, the loss of the services of our chief executive officer, chief financial officer and chief operating officer could negatively impact our future operations. We have employment agreements with these key 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 financial condition, future cash flows and the results of operations.

Our major shareholder may influence the activities and operations of certain jointly owned properties, which also could result in conflicts of interest.

As of December 31, 2007, Chesapeake Energy Corporation owned approximately 16.3% of our outstanding common shares. As a result, Chesapeake is in a position to heavily influence the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of or amendment to provisions in our Amended and Restated Articles of Incorporation, Bylaws and the approval of mergers and other significant corporate transactions. Their 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. Chesapeake has the right to have an observer present at our board of directors meetings.

Chesapeake and its subsidiaries are also engaged in the natural gas and oil business. Although we have entered into a joint operating agreement with Chesapeake, it is possible that we may in some circumstances be in direct or indirect competition with Chesapeake, including competition with respect to certain business strategies and transactions that we may propose to undertake. These conflicts of interest may have a material adverse affect our results of operations.

 

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

Two 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. Investors should not assume that Canadian courts will enforce judgments of United States courts obtained in actions against those directors predicated upon the civil liability provisions of the United States federal securities laws or the securities or “blue sky” laws of any state within the United States or will enforce, in original actions, liabilities against those directors upon the United States federal securities laws or any such state securities or blue sky laws.

A change of control of the Company could have a material adverse effect on us, and if GeoStar prevails in its “look back” claim, it could result in a change of control of the Company.

Under the terms or agreements for our 12  3 / 4 % Senior Secured Notes, the Revolving Credit Facility and the convertible senior debentures, which collectively constitute substantially all of our indebtedness, upon the occurrence of specific types of changes of control in the Company, we will be required to either repay or make an offer to repurchase all outstanding debt under these agreements. If such a change of control were to occur, including as a result of payment of a disputed look back payment if GeoStar were to prevail in its assertion discussed elsewhere in this report, we may not have sufficient funds available to repay debt becoming due or repurchase debt tendered to us. In that event, we would need to seek waivers from lenders and debtholders, which may not be obtainable, or a refinancing, which may not be available or on terms as favorable as the refinanced debt. Such a required repayment, repurchase or refinancing could have a material adverse effect on our financial condition, future cash flows and the results of operations.

Risk Factors Related to 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 are beyond our control. Information about the market price of our common shares since trading commenced on the American Stock Exchange on January 5, 2006 is set forth in Item 5. “Market for Registrant’s Common Equity and Related Shareholder Matters and Issuer Purchases of Equity Securities—Market Information”.

In addition, the stock market in general and the market for natural gas and oil exploration companies in particular have experienced large 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 material adverse effect on our financial condition, future cash flows and the results of 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 common shares or securities convertible into common shares.

 

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Our ability to issue an unlimited number of our common shares under our articles of incorporation may result in dilution or make it more difficult to effect a change in control of the Company, which could adversely affect the price of our common shares.

Unlike most corporations formed in the United States, our Amended and Restated Articles of Incorporation chartered under the laws of the Province of Alberta, Canada permit the board of directors to issue an unlimited number of new common shares without shareholder approval, subject only to the rules of the American Stock Exchange and the Toronto Stock Exchange or any future exchange on which our common shares might trade. The issuance of a large number of common shares could be effected by our directors to thwart a takeover attempt or offer for us by a third party, even if doing so would not benefit our shareholders, which could result in the common shares being valued less in the market. The issuance, or the threat of issuance, of a large number of common shares, at prices that are dilutive to the outstanding common shares could also result in the common shares being valued less in the market.

Failure to register our 12  3 / 4 % Senior Secured Notes that were sold in a November 2007 private placement could result in us being required to pay additional interest, which could be significant.

On November 29, 2007, we sold $100.0 million of our 12  3 / 4 % Senior Secured Notes. We are obligated to prepare and file with the SEC within 150 days of the issue date of the 12  3 / 4 % Senior Secured Notes, or April 27, 2008, a registration statement to exchange the 12  3 / 4 % Senior Secured Notes for registered, publicly tradable notes that have substantially identical terms as the 12  3 / 4 % Senior Secured Notes. We are to use our best efforts to cause the registration statement to be declared effective within 240 day of the issue date of the 12  3 / 4 % Senior Secured Notes, or July 24, 2008. In the event we fail to meet our registration obligations we will be required to pay additional cash interest on the 12  3 / 4 % Senior Secured Notes equal to 0.25% per annum for the first 90-day period, increasing an additional 0.25% the next 90-day period, to a maximum of 0.50% per annum.

Issuance of the common shares upon conversion of our convertible debenture 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 conversion of our convertible debentures. These issuances will dilute the ownership interest of existing shareholders. Any sales in the public market of the common shares issuable upon conversion of additional common shares could adversely affect prevailing market prices of our common shares. In addition, the existence of these convertible debentures may encourage short selling by market participants.

 

Item 1B. Unresolved Staff Comments

None.

 

Item 2. Properties

Our properties consist primarily of natural gas, oil and mineral lease and concession interests in the following areas:

 

   

Hilltop area of East Texas;

 

   

Powder River Basin in Wyoming and Montana;

 

   

Gunnedah Basin in New South Wales, Australia; and

 

   

Gippsland Basin in Victoria, Australia.

Additional information concerning our interests in these areas is described under Item 1. Business.

 

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Production, Prices and Operating Expenses

The following table presents information regarding the production volumes, average sales prices received and average production costs associated with our sales of natural gas and oil for the periods indicated. Oil and condensate are compared with natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil or condensate is the energy equivalent of six Mcf of natural gas.

 

     For the Years Ended
December 31,
         2007            2006    

Production:

     

Natural gas (MMcf)

     6,576      4,646

Oil (MBbl)

     8      12

Total (MMcfe)

     6,621      4,716

Natural gas (MMcfd)

     18.0      12.7

Oil (MBod)

     0.1      0.2

Total (MMcfed)

     18.1      12.9

Average sales prices:

     

Natural gas (per Mcf)

   $ 5.18    $ 5.60

Oil (per Bbl)

   $ 66.17    $ 64.66

Selected data per Mcfe:

     

Lease operating, transportation and selling expenses

   $ 1.32    $ 1.82

General and administrative expenses

   $ 2.13    $ 2.87

Depreciation, depletion and amortization of natural gas and oil properties

   $ 3.24    $ 3.46

Drilling Activity

The following table shows our drilling activity for the periods indicated. In the table, “gross” wells refer to wells in which we have a working interest, and “net” wells refer to gross wells multiplied by our working interest in such wells. “Undecided” wells are CBM 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.

 

     For the Years Ended
December 31,
     2007    2006
     Gross    Net    Gross    Net

Exploratory wells:

           

Productive

   4    2.2    4    2.3

Non-productive

   1    0.3    1    0.3

Under evaluation

   10    7.5    9    3.2
                   

Total

   15    10.0    14    5.8
                   

Development wells:

           

Productive

   31    14.8    43    19.5

Non-productive

   —      —      —      —  
                   

Total

   31    14.8    43    19.5
                   

 

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Exploration and Development Acreage

The following table sets forth our ownership interest in undeveloped and developed acreage in the areas indicated where we own a working interest as of December 31, 2007. Gross represents the total number of acres in which we own a working interest. Net represents our proportionate working interest resulting from our ownership in gross acres.

 

     Undeveloped Acreage    Developed Acreage
     Gross    Net    Gross    Net

Hilltop area, East Texas

   28,494    12,144    6,942    4,106

Powder River Basin, Wyoming and Montana

   33,917    11,992    21,049    9,862

Other

   7,017    5,782    —      —  
                   

Total United States

   69,428    29,918    27,991    13,968
                   

Gunnedah Basin, New South Wales

   6,047,150    2,116,503    2,200    770

Gippsland Basin, Victoria

   1,000,000    750,000    —      —  
                   

Total Australia

   7,047,150    2,866,503    2,200    770
                   

Productive Wells

The following table sets forth our working interest ownership in productive economic wells in the areas indicated as of December 31, 2007, based on our third party reservoir engineering report. Gross represents the total number of wells in which we own a working interest. Net represents our proportionate working interest resulting from our ownership in gross wells. Productive wells are wells that are capable of producing natural gas or oil in economic quantities. Wells that are completed in more than one producing horizon are counted as one well.

 

     Productive Wells
     Natural Gas    Oil    Total Wells
     Gross    Net    Gross    Net    Gross    Net

Hilltop area, East Texas

   17    12.0    —      —      17    12.0

Powder River Basin, Wyoming and Montana

   283    125.2    —      —      283    125.2
                             

Total United States

   300    137.2    —      —      300    137.2
                             

As of December 31, 2007, we had no commercially productive wells in Australia.

 

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Natural Gas and Oil Reserves

Our estimated total net proved reserves of natural gas and oil as of December 31, 2007 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 NSAI and are part of their reserve reports on our natural gas and oil properties. The estimates of NSAI were based on a review of geologic, economic, ownership and engineering data that we provided.

In accordance with SEC regulations, estimates of our proved reserves and future net revenues are made using sales prices in effect as of the date of the 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 are affected by natural gas and oil prices, which have fluctuated significantly in recent years. Our estimated proved reserves have not been filed with or included in reports to any U.S. federal agency.

 

     Total Proved Reserves as of December 31, 2007
     Producing    Non-producing    Undeveloped    Total

Natural gas (MMcf)

     21,778      12,280      20,764      54,822

Oil (MBbls)

     9      —        —        9

Total proved reserves (MMcfe)

     21,831      12,280      20,764      54,875

Standardized measure of discounted future net cash flow (000)

   $ 70,374    $ 40,160    $ 21,698    $ 132,232

Pricing Assumptions

SEC regulations require that the natural gas and oil prices used in the NSAI reserve reports are the period-end prices for natural gas and oil at December 31, 2007. These prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve reports but are adjusted by lease for energy content, quality, transportation, compression and gathering fees, and regional price differentials. The pricing assumptions are listed below:

 

     As of December 31, 2007
     Gas ($/MMBtu)    Oil ($/Bbl)

Production:

     

Hilltop Area, East Texas

   $ 6.795    $ 92.50

Powder River Basin, Wyoming and Montana

   $ 6.040    $ —  

The weighted average natural gas and oil prices after basis adjustments used in our reserve valuation as of December 31, 2007 were $6.08 per Mcf and $93.88 per barrel.

The prices used in calculating the estimated future net revenue attributable to proved reserves do not reflect market prices for natural gas and oil production sold subsequent to December 31, 2007. There can be no assurance that all of the estimated proved reserves will be produced and sold at the assumed prices. Accordingly, the foregoing prices should not be interpreted as a prediction of future prices.

For additional information concerning our estimated proved reserves, the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2007, 2006 and 2005 and the changes in quantities and standardized measure of such reserves for each of the three years then ended, see Note 21—Supplemental Oil & Gas Disclosures—Unaudited to our consolidated financial statements, which begin on page F-1.

 

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Item 3. Legal Proceedings

Information about our legal proceedings is set forth in Note 16.—Commitments and Contingencies—Litigation to our consolidated financial statements, which begin on page F-1.

 

Item 4. Submission of Matters to a Vote of Security Holders

During the three months ended December 31, 2007, no matters were submitted to a vote of security holders.

 

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PART II

 

Item 5. Market for Registrant’s Common Equity and Related Shareholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common shares are traded on the American Stock Exchange under the symbol “GST” and the Toronto Stock Exchange under the symbol “YGA”.

The following table sets forth the high and low sale prices of our common shares as reported on the American Stock Exchange, and as reported on the Toronto Stock Exchange for the periods presented. The prices in the table below have been adjusted for stock splits.

 

     American
Stock Exchange
   Toronto
Stock Exchange
         High            Low        High    Low

2007

           

Fourth quarter

   $ 1.87    $ 0.90    CDN$ 1.71    CDN$ 0.90

Third quarter

   $ 2.25    $ 1.40    CDN$ 2.49    CDN$ 1.40

Second quarter

   $ 2.35    $ 1.94    CDN$ 2.70    CDN$ 2.00

First quarter

   $ 2.41    $ 1.50    CDN$ 2.78    CDN$ 1.81

2006

           

Fourth quarter

   $ 2.56    $ 2.03    CDN$ 2.91    CDN$ 2.20

Third quarter

   $ 3.14    $ 2.00    CDN$ 3.70    CDN$ 2.24

Second quarter

   $ 4.37    $ 2.10    CDN$ 5.12    CDN$ 2.27

First quarter

   $ 5.98    $ 3.60    CDN$ 6.73    CDN$ 4.05

The last reported sale prices of our common shares on the American Stock Exchange and the Toronto Stock Exchange on March 13, 2008 were $1.38 and CDN$1.40, respectively.

Shareholders

As of March 10, 2008, there were 370 shareholders of record who owned our common shares.

Dividends

We have never declared or paid any cash dividends on our common shares. We anticipate that we will retain 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 12  3 / 4 % Senior Secured Notes and revolving credit facility contain covenants that 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.

Recent Sales of Unregistered Securities; Use of Proceeds from Unregistered Securities

During the year ended December 31, 2007, we sold the following securities without registration under the Securities Act:

On March 19, 2007, the eighteen-month anniversary of the September 19, 2005 $10.0 million senior secured notes issuance, the Company issued to the note holders an additional 375,939 common shares valued at CDN$714,286. The issuance of the common shares was exempt from registration pursuant to Section 3(a)(9) of the Securities Act.

 

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On May 9, 2007, the Company completed the sale of a portion of the Company’s East Texas undeveloped natural gas and oil acreage to a third party for total consideration, transaction costs, of $88.2 million, including the purchase of 10.0 million newly issued Gastar common shares at a price of $2.00 per share, or $20 million. The issuance of the common shares was exempt from registration pursuant to Rule 506 of Regulation D of the Securities Act.

On May 23, 2007 in conjunction with the May 9, 2007 sale of 10.0 million newly issued common shares, Chesapeake acquired an additional 1,757,195 of the Company’s common shares at $2.00 per share pursuant to its preemptive rights under a Common Stock Purchase Agreement dated November 4, 2005. The issuance of the common shares was exempt from registration pursuant to Rule 506 of Regulation D of the Securities Act.

 

Item 6. Selected Financial Data

The following table presents selected historical financial data as of and for the periods indicated. The selected consolidated financial data are derived from our audited consolidated financial statements.

 

     As of and For the Years Ended December 31,  
     2007     2006     2005     2004     2003  
     (in thousands, except per share data)  

Consolidated Statements of Loss:

          

Revenues

   $ 34,565     $ 26,765     $ 27,442     $ 6,059     $ 1,461  

Loss from operations

   $ (42,514 )   $ (71,070 )   $ (10,963 )   $ (9,587 )   $ (2,368 )

Net loss

   $ (30,540 )   $ (84,839 )   $ (25,692 )   $ (12,776 )   $ (4,947 )

Basic and diluted loss per share

   $ (0.15 )   $ (0.50 )   $ (0.20 )   $ (0.12 )   $ (0.05 )

Shares used in the calculation of basic and diluted loss per share

     202,829       170,015       129,399       111,374       104,958  

Consolidated Balance Sheet:

          

Property plant and equipment, net

   $ 157,120     $ 160,826     $ 165,347     $ 56,564     $ 37,725  

Total assets

   $ 261,750     $ 228,889     $ 240,128     $ 84,442     $ 38,757  

Long-term liabilities

   $ 137,076     $ 98,627     $ 105,410     $ 60,668     $ 10,554  

Total shareholders’ equity

   $ 95,269     $ 98,342     $ 120,776     $ 21,976     $ 23,669  

Additional pro forma information about the 2005 GeoStar Acquisition is set forth in Note 5—GeoStar Acquisition to our consolidated financial statements, which begin on page F-1.

 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with accompanying consolidated financial statements and related notes included in Item 8, “Financial Statements and Supplementary Data”, which begin on page F-1. 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, the impact of acquisitions, changes due to the adoption of FASB No. 123R, 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 Form 10-K, 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.

 

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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 CBM. We are also pursuing unconventional natural gas exploration in the deep Bossier play in the Hilltop area in East Texas. Our primary CBM properties are in the United States in the Powder River Basin in Wyoming and Montana and in the Gunnedah and Gippsland Basins of Australia.

Our major domestic asset is approximately 35,400 gross (16,300 net) acres in the Bossier play in the Hilltop area of East Texas. During the past three years, we spent approximately $196.6 million in acreage, seismic and reserve acquisition and exploratory and development drilling on this acreage. While we have not attained positive net income from operations in the past three years, and there can be no assurance that operating income and net earnings will be achieved in future periods, our recent efforts have resulted in significant growth in production over the past three-year period. As we continue the exploitation and development drilling in the Hilltop area, we expect to show further improvement in our operations.

Our international activities are focused on CBM development in Australia on over 6.0 million gross (2.1 million net) acres in New South Wales. We are in the early stages of development of this potentially significant asset, which could have a material and positive long-term impact on our financial results. Although we currently have no commercial production, we and our joint venture partner have been approached by potential buyers with an interest in potentially contracting for future deliveries of natural gas from PEL 238 for use in the generation of electricity. In September 2007, NSAI certified a quantity of proved and probable reserves under guidelines established by the Society of Petroleum Engineers (“SPE”), as a result of the success of one of our pilot production projects on PEL 238. These reserves, however, are not yet established as proved reserves under SEC guidelines nor can we assure that other unevaluated acreage will contain similar reserves.

Our financial results depend upon many factors which significantly affect our results of operations including the following:

 

   

The level and success of exploration and development activity;

 

   

The sales prices of natural gas and crude oil;

 

   

The level of total sales volumes of natural gas and crude oil; and

 

   

The availability of and our ability to raise the capital necessary to meet our cash flow and liquidity needs.

We plan our activities and budget based on conservative sales price assumptions, given the inherent volatility of natural gas and oil prices that are influenced by many factors beyond our control. We focus our efforts on increasing natural gas and oil reserves and production and strive to control costs at an appropriate level. Our future earnings and cash flows are dependent on our ability to manage our overall cost structure to a level that allows for profitable production. Our future earnings will also be impacted by the changes in the fair market value of hedges we executed to mitigate the volatility in the changes of natural gas and oil prices in future periods. These instruments meet the criteria to be accounted for as cash flow hedges, and until settlement, the changes in fair market value of our hedges will be included as a component of stockholder’s equity to the extent effective in periods of rising prices, these transactions will mitigate future earnings and in periods of declining prices will increase future earnings in the respective period the positions are settled.

Like other natural gas and oil exploration and production companies, we face the fact of natural production declines. As initial reservoir pressures are depleted, natural gas and oil production from a given well will decrease. Thus, a natural gas and oil exploration and production company depletes part of its asset base with each

 

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unit of natural gas and oil it produces. We attempt to overcome this natural decline by adding reserves in excess of what we produce through successful drilling or acquisition. Our future growth will depend on our ability to continue to add reserves in excess of our production. We will maintain our focus on adding reserves through drilling and acquisitions, while placing a clear priority on lowering our cost of replacing reserves. Consistent with our stated strategies, we will emphasize maintaining a high-quality inventory of drilling locations, while also focusing on improving our capital and cost efficiency.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, contingent assets and liabilities and the related disclosures in the accompanying consolidated financial statements. Changes in these estimates and assumptions could materially affect our financial position, results of operations or cash flows. Management considers an accounting estimate to be critical if:

 

   

It requires assumptions to be made that are uncertain at the time the estimate is made; and

 

   

Changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated results of operations or financial condition.

All other significant accounting policies that we employ are presented in the notes to the consolidated financial statements. The following discussion presents information about the nature of our most critical accounting estimates, our assumptions or approach used and the effects of hypothetical changes in the material assumptions used to develop each estimate.

Full Cost Method of Accounting

We follow the full cost method of accounting for natural gas and oil operations, whereby all costs incurred in the acquisition, exploration and development of natural gas and oil reserves are initially capitalized into cost centers on a country-by-country basis. Our current cost centers are located in the United States and Australia. Such costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development 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. The percentage of total reserve volumes produced during the year is multiplied by the net capitalized investment plus future estimated development costs in those reserves.

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.

In applying the full cost method, we perform a quarterly ceiling test on the cost center properties whereby the net cost of natural gas and oil properties, net of related deferred income taxes (“net cost”), is limited to the sum of the estimated future net revenues from proved reserves using prices in effect at the end of the period held constant, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“ceiling”). If the net cost exceeds the ceiling, an impairment loss is recognized for the amount by which the net cost exceeds the ceiling and is shown as a reduction in natural gas and oil properties and 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.

 

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Natural Gas and Oil Reserves

Nature of Critical Estimate Item.     Our estimate of proved reserves is based on the quantities of natural gas and oil which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the economics of producing the reserves may change and therefore the estimate of proved reserves also may change. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent imprecision in these engineering estimates, our proved reserve volumes and values are used to calculate depletion and impairment provisions.

“Ceiling” Limitation Test—The full cost method of accounting for natural gas and oil properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full cost ceiling calculation. The ceiling is the discounted present value of our estimated total proved reserves using a 10% discount rate. To the extent that our capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense. Once incurred, this impairment of natural gas and oil properties is not reversible at a later date even if natural gas and oil prices increase. Impairments were required at December 31, 2006 and at June 30, 2007. The calculation of our proved reserves could significantly impact our ceiling limitation used in determining whether an impairment of our capitalized costs is necessary. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are generally held constant indefinitely, but subsequent period end prices may be used if such prices would reduce the ceiling impairment. Therefore, the future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs, but rather are based on prices and costs in effect at the time of evaluation. The weighted average natural gas after basis adjustments used in the reserve valuations as of December 31, 2006 and June 30,2007 were $6.12 per Mcf and $5.72 per Mcf, respectively.

The most likely factor to contribute to a ceiling test impairment is the price used to calculate the reserve limitation threshold. A significant reduction in the prices at a future measurement date could trigger a full cost ceiling impairment. At December 31, 2007, we had a ceiling impairment cushion of $45.2 million. A 10% decrease in prices would have resulted in a decrease in the cushion of approximately $24.1 million. A 10% increase in prices used would have resulted in an increase in the cushion approximately $20.7 million.

Assumptions/Approach Used.     Units-of-production method is used to amortize our natural gas and oil properties. A change in the quantity of reserves could significantly impact our depletion expense. A reduction in proved reserves, without a corresponding reduction in capitalized costs, will increase our depletion rate.

Effect if different assumptions used.     A 10% increase in reserves would have decreased our depletion expense for the year ended December 31, 2007 by approximately 2%, while a 10% decrease in reserves would have increased our depletion expense by approximately 3%.

Unproved Property Impairment

Nature of Critical Estimate Item.     We have elected to use the full cost method to account for our natural gas and oil activities. Investments in unproved properties are not amortized until proved reserves associated with the properties can be determined or until impairment occurs. Unproved properties are evaluated quarterly for impairment on a field basis. If the results of an assessment indicate that an unproved property is impaired, the amount of impairment is added to the proved natural gas and oil property costs to be amortized.

Assumptions/Approach Used.     At December 31, 2007, we had $46.5 million allocated to unproved United States property costs which was comprised primarily of unevaluated acreage costs. The unproven property costs

 

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are evaluated by the technical team and management of whether the property has potential attributable reserves. Therefore, the assessment made by our technical team and management of the potential reserves will determine whether costs are moved from the unproved category to the full-cost pool for depletion or whether an impairment is taken.

Effect if different assumptions used.     A 10% increase or decrease in the unproved property balance would have decreased or increased our depletion expense by approximately 1% for the year ended December 31, 2007.

Asset Retirement Obligation

Nature of Critical Estimate Item.     We have certain obligations to remove tangible equipment and restore land at the end of natural gas and oil production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells. Under Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations”, as discussed in Note 2 to our consolidated financial statements, we estimate asset retirement costs for all of our assets, inflation adjust those costs to the forecast abandonment date, discount that amount using a credit-adjusted-risk-free rate back to the date we acquired the asset or obligation to retire the asset and record an asset retirement obligation, or ARO, liability in that amount with a corresponding addition to our capitalized cost. We then accrete the liability quarterly using the period-end effective credit-adjusted-risk-free rate. As new wells are drilled or purchased, their initial asset retirement cost and liability is calculated and recorded. Should either the estimated life or the estimated abandonment costs of a property change upon our quarterly review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost (included in the full-cost pool); therefore, abandonment costs will almost always approximate the estimate. When wells are sold the related liability and asset costs are removed from the balance sheet.

Assumptions/Approach Used.     Estimating the future asset removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the estimate of the present value calculation of our AROs are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted-risk-free-rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments.

Effect if different assumptions used.     Since there are so many variables in estimating AROs, we attempt to limit the impact of management’s judgment on certain of these variables by using input of qualified third parties. We engage independent petroleum engineers, who have consented to the use of their name and reports in this Form 10-K, to evaluate our properties annually. We primarily use the remaining estimated useful life from the year end reserve reports by our independent reserve engineer in estimating when abandonment could be expected for each property as an estimate based on field or industry practices. We expect to see our calculations impacted significantly if interest rates move from their current levels, as the credit-adjusted-risk-free rate is one of the variables used on a quarterly basis. Our technical team developed a standard cost estimate based on historical costs, industry quotes and depth of wells. Unless we expect a well’s plugging to be significantly different than a normal abandonment, we use this estimate. The resulting estimate, after application of a discount factor and some significant calculations, could differ from actual results, despite all our efforts to make an accurate estimate.

Capitalized Interest

We capitalize interest for two purposes:     (1) capitalized interest on funds borrowed for specific projects, such as our long-term development of our CBM assets in New South Wales and Victoria, Australia and (2) capitalized interest on borrowed funds used to invest in unproven natural gas and oil properties not being

 

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amortized. The methodology for capitalizing interest on general funds, consistent with SFAS No. 34, “Capitalization of Interest Cost,” begins with a determination of the borrowings applicable to our qualifying assets. The basis of this approach is the assumption that the portion of the interest costs that are capitalized on expenditures during an asset’s acquisition period could have been avoided if the expenditures had not been made. This methodology takes the view that if funds are not required for construction then they would have been used to pay off other debt. We use our best judgment in determining which borrowings represent the cost of financing the acquisition of the assets. The primary debt instruments included in the rate calculation of interest incurred on the funds is our 12  3 / 4 % Senior Secured Notes. The interest to be capitalized for any period is derived by multiplying this fixed rate of interest times the average qualifying assets during the period. To qualify for interest capitalization, we must continue to make progress on the development of the assets.

Stock-Based Compensation

Nature of Critical Estimate Item.     Effective January 1, 2003, we adopted the provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”), using the prospective application method of SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure”. This statement required us to record compensation costs for options granted under our stock option plan in accordance with the fair value method prescribed in SFAS No. 123.

Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS 123(R), “Share-Based Payment”, using the modified-prospective method. Under that method, compensation cost for 2007 and 2006 includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of, January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (b) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS 123(R).

The Company reports compensation expense for stock options and restricted common shares granted to officers, directors and employees using the fair value method in accordance with SFAS 123R. Stock-based compensation costs are recorded over the requisite service period, which approximates the vesting period.

The fair value of each stock option grant is estimated on the date of grant using the Black-Scholes-Merton valuation pricing model. The fair value of all awards is expensed using the “graded-vesting method”, which recognizes compensation costs over the requisite service period for each separately vesting tranche of an award as though the award were, in substance, multiple awards.

Assumption/Approach Used.     The Black-Scholes-Mertron model requires various highly judgmental assumptions including volatility, expected option life and forfeiture rate. If any of the assumptions used in the Black-Scholes-Mertron model change significantly, stock-based compensation expense may differ materially in the future from that recorded in the current period. The table below summarizes the key assumptions for the stock options granted for the periods indicated:

 

     For the Years
Ended December 31,
 
     2007      2006  

Expected volatility

   44.4-44.7 %    45.7 %

Expected life (in years)

   6.25      6.5  

Expected forfeitures

   5.0 %    5.0 %

Effect if different assumptions used.     A 10% increase or decrease in the volatility rate would increase or decrease our stock based compensation for the year ended December 31, 2007 by approximately 6.4% and 6.6%, respectively. A 10% increase or decrease in expected life would increase or decrease our stock based compensation expense for the year ended December 31, 2007 by approximately 4.6% and 4.9%, respectively. A 10% increase or decrease in forfeiture rate would have a corresponding impact on our stock based compensation expense for the year ended December 31, 2007.

 

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Results of Operations

The following is a comparative discussion of the results of operations for the periods indicated. It should be read in conjunction with the consolidated financial statements and the related notes to the consolidated financial statements, which begin on page F-1.

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

 

     For the Years Ended December 31,
         2007            2006            2005    

Production:

        

Natural gas (MMcf)

     6,577      4,646      3,810

Oil (MBbl)

     7      12      2

Total (MMcfe)

     6,621      4,716      3,822

Natural gas (MMcfd)

     18.0      12.7      10.5

Oil (MBod)

     0.1      0.2      0.0

Total (MMcfed)

     18.1      12.9      10.5

Average sales prices:

        

Natural gas (per Mcf)

   $ 5.18    $ 5.60    $ 7.18

Oil (per Bbl)

   $ 66.17    $ 64.66    $ 50.85

Year Ended December 31, 2007 compared to Year Ended December 31, 2006

Revenues.     Substantially all of our revenues are derived from the production of natural gas in the United States. Revenues were $34.6 million for the year ended December 31, 2007, up 29% from $26.8 million for the year ended December 31, 2006. The increase in revenues was the result of a 42% increase in natural gas production primarily in East Texas, which was partially offset by an 8% decrease in natural gas prices.

Production taxes.     We reported production taxes of $765,000 for the year ended December 31, 2007, down from $1.5 million for the year ended December 31, 2006. This decrease was the result of tight sand credit refunds on our Texas natural gas sales and lower Wyoming taxes due to gas price declines.

Lease operating expenses.     We reported lease operating expenses of $6.3 million for the year ended December 31, 2007, up from $5.5 million for the year ended December 31, 2006. This increase was due to an increased number of producing wells and increased production. Our lease operating expenses were $0.95 per Mcfe for the year ended December 31, 2007, compared to $1.18 per Mcfe for the comparable period in 2006.

Transportation and treating.     We reported transportation expenses of $1.6 million for the years ended December 31, 2007 and 2006. Transportation and treating expense was constant as it relates to our Powder River Basin CBM production, which did not change significantly from 2006.

Depreciation, depletion and amortization.     Depreciation, depletion and amortization was $21.5 million for the year ended December 31, 2007, up from $16.3 million for the year ended December 31, 2006. The increase in DD&A expense was the result of a 40% increase in production, primarily attributable to new East Texas wells drilled during 2007. The DD&A rate for the year ended December 31, 2007 was $3.22 per Mcfe, as compared to $3.44 for the comparable period in 2006.

Impairment of natural gas and oil properties.     Impairment of U.S. natural gas and oil properties was $28.5 million for the year ended December 31, 2007, compared to $56.3 million for the comparable period ended December 31, 2006. The 2007 impairment is the result of net natural gas and oil property costs, as adjusted for

 

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related deferred income taxes, if any, and other adjustments, exceeding the sum of estimated future net revenues using weighted average after basis adjustment prices in effect at June 30, 2007, the date of the impairment, held constant at $5.72 per Mcf for natural gas, discounted at 10%, and unproven properties at historical costs of $43.6 million. The 2006 impairment was the result of net natural gas and oil property costs, as adjusted for related deferred income taxes and other adjustments, exceeding the sum of estimated future net revenues using post end of period weighted average after basis adjustment prices held constant of $6.11 per Mcf for natural gas, discounted at 10%, and unproven property at historical cost of $81.5 million, as adjusted for related income taxes and other adjustments.

General and administrative.     We reported general and administrative expenses of $16.9 million for the year ended December 31, 2007, up from $13.5 million for the year ended December 31, 2006. This increase in general and administrative expenses was primarily due to an increase in allowance for doubtful accounts and professional service charges, including Sarbanes-Oxley compliance costs, partially offset by a decline in contract personnel costs. The allowance for doubtful accounts was increased by $3.7 million to fully reserve the GeoStar receivable due to current litigation. Non-cash stock-based compensation expense pursuant to the SFAS 123R, which is included in general and administrative expenses, was $3.9 million for both years ended December 31, 2007 and 2006.

Litigation settlement expense .    The $1.4 million litigation settlement expense incurred in 2007 was primarily the result of an accrual of a settlement payment related to a proposed settlement with GeoStar on certain matters. The settlement proposal was never finalized (Note 16—Commitments and Contingencies —Litigation—Arbitration and Litigation with GeoStar Corporation and Affiliates). The $2.4 million litigation settlement expense incurred in 2006 was primarily the result of a settlement payment regarding Western Gas Resources, Inc., et. al . litigation involving a gas gathering agreement and its applicability to properties we exchanged in 2002 and settlement of the Burning Rock Energy LLC, et. al. litigation by assigning our interest in certain disputed properties.

Interest expense.     We reported interest expense of $14.1 million for the year ended December 31, 2006, compared to $15.6 million for the year ended December 31, 2006. The decrease in interest expense was primarily the result of $1.9 million of capitalized interest in 2007, resulting from capital activity expansion in Texas and Australia. Interest expense includes deferred cost and debt discount amortization of $4.2 million for 2007, a decrease of $100,000 from the comparable 2006 period. There was no capitalized interest in 2006

Debt extinguishment expense.     We reported debt extinguishment expense of $15.7 million for the year ended December 31, 2007. This resulted from the expensing of a prepayment penalty of $3.7 million and deferred financing and debt discount costs of $12.0 million incurred related to $73.0 million of senior secured notes. The senior secured notes were repaid prior to maturity with the proceeds from the sale of $100.0 million of 12  3 / 4 % Senior Secured Notes in November 2007. There was no debt extinguishment expense in 2006.

Year Ended December 31, 2006 compared to Year Ended December 31, 2005

Revenues.     Substantially all of our revenues are derived from the production of natural gas in the United States. Revenues were $26.8 million for the year ended December 31, 2006, down from $27.4 million for the year ended December 31, 2005. The decrease in revenues was the result of a 21% decrease in natural gas prices, which was partially offset by a 23% increase in production.

Production taxes.     We reported production taxes of $1.5 million for the year ended December 31, 2006, up from $1.1 million for the year ended December 31, 2005. This increase was the result of increased production from new wells and a $350,000 tight sands gas tax refund in 2005.

Lease operating expenses.     We reported lease operating expenses of $5.5 million for the year ended December 31, 2006, up from $3.9 million for the year ended December 31, 2005. This increase was due to an increase in the number of producing wells. Our lease operating expenses were $1.18 per Mcfe for the year ended December 31, 2006, compared to $1.01 per Mcfe for the comparable period in 2005.

 

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Transportation and treating.     We reported transportation expenses of $1.6 million for the year ended December 31, 2006, down from $2.0 million for the year ended December 31, 2005. The decrease in expense was primarily the result of lower Powder River Basin transportation costs. This decrease was the result of a decrease in per Mcf cost from $1.43 per Mcf in 2005 to $0.88 per Mcf in 2006.

Depreciation, depletion and amortization.     Depreciation, depletion and amortization was $16.3 million for the year ended December 31, 2006, up from $13.9 million for the year ended December 31, 2005. This increase primarily was attributable to new East Texas wells drilled and placed into production during 2006 and additional production from new CBM wells drilled in the Powder River Basin. The increase in DD&A expense was the result of a 23% increase in production, which was partially offset by a 5% decrease in the DD&A rate per unit of production. The DD&A rate for the year ended December 31, 2006 was $3.44 per Mcfe, as compared to $3.63 for the comparable period in 2005.

Impairment of natural gas and oil properties.     Impairment of U.S. natural gas and oil properties was $56.3 million for the year ended December 31, 2006, compared to $8.7 million for the comparable period ended 2005. The 2006 impairment was the result of net natural gas and oil property costs, as adjusted for related deferred income taxes and other adjustments, exceeding the sum of estimated future net revenues using post end of period weighted average after basis adjustment prices held constant of $6.11 per Mcf for natural gas, discounted at 10%, and unproven property at historical cost of $81.5 million, which was lower than the estimated fair market value, as adjusted for related income taxes and other adjustments. The 2005 impairment was the result of net natural gas and oil property costs, as adjusted for related deferred income taxes, if any, and other adjustments, exceeding the sum of estimated future net revenues using prices in effect at June 30, 2005, the date of the impairment, held constant at $5.32 per Mcf for natural gas, discounted at 10%, and unproven properties at historical costs of $93.3 million, as adjusted for related deferred income taxes and other adjustments.

General and administrative.     We reported general and administrative expenses of $13.5 million for the year ended December 31, 2006, up from $8.7 million for the year ended December 31, 2005. This increase in general and administrative expenses was primarily due to increases in staff, contract personnel and professional service charges, and the recording of non-cash compensation expense due to the granting of stock options. Non-cash stock-based compensation expense for 2006 pursuant to the SFAS 123R, which is included in general and administrative expenses, was $3.9 million, up from $2.3 million in 2005.

Litigation settlement expense .    The $2.4 million litigation settlement expense incurred in 2006 was primarily the result of a settlement payment regarding Western Gas Resources, Inc., et. al ., of a lawsuit involving a gas gathering agreement and its applicability to properties we exchanged in 2002 and settlement of the Burning Rock Energy LLC, et. al. litigation by assigning our interest in certain disputed properties. There was no litigation settlement expense in 2005.

Interest expense.     We reported interest expense of $15.6 million for the year ended December 31, 2006, compared to $13.9 million for the year ended December 31, 2005. The increase in interest expense was the result of higher average debt outstanding and higher interest rates. Interest expense includes deferred financing cost and debt discount amortization of $4.3 million for 2006, a decrease of $500,000 from 2005.

Debt extinguishment expense.     In June 2005, in conjunction with the issuance of the senior secured notes, the Company retired certain senior notes, resulting in a debt extinguishment expense of $1.4 million, comprised of $662,000 of early prepayment penalty and $694,000 of unamortized deferred financing costs.

Liquidity and Capital Resources

At December 31, 2007, we had cash and cash equivalents of $85.9 million. For the year ended December 31, 2007, we reported cash flow from operations of $7.4 million. Capital expenditures on natural gas and oil properties totaled $74.2 million, excluding property divestments, during the period for the year ended December 31, 2007.

 

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On November 29, 2007, Gastar USA sold $100.0 million aggregate principal amount of 12  3 / 4 % Senior Secured Notes at an issue price of 99.50%. Approximately $76.7 million of the $92.5 million net proceeds from the offering was used to repay the $73.0 million of our outstanding senior secured notes, with the remaining net proceeds used for general corporate purposes. The 12  3 / 4 % Senior Secured Notes mature on December 1, 2012. The 12  3 / 4 % Senior Secured Notes contain certain covenants that among other things limit Gastar USA’s and the guarantors’ ability to: (i) incur additional indebtedness; (ii) pay distributions on, or repurchase or redeem equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into certain transactions with affiliates; and (vi) sell assets or consolidate or merge into other companies. Notwithstanding the above, we may incur other indebtedness, which would be subordinate to the 12  3 / 4 % Senior Secured Notes, up to an aggregate $25.0 million of indebtedness under the Revolving Credit Facility or such additional amounts of 12  3 / 4 % Senior Secured Notes; provided, that Gastar USA’s consolidated cash flow to fixed charges for the most recent four quarters giving the effect of the incurrence at the beginning of such four-quarter-period is at least 2.0 to 1.0.

On November 29, 2007, concurrent with the closing of the 12  3 / 4 % Senior Secured Notes, Gastar USA entered into a Revolving Credit Facility, which provides for an initial first priority lien borrowing base of $19.4 million. At December 31, 2007, there were no amounts outstanding under the Revolving Credit Facility.

Covenants in our 12¾% Senior Secured Notes Indenture, our indenture governing our 9.75% convertible senior unsecured subordinated debentures and our Revolving Credit Facility agreement require us to make an offer to repurchase or repay all of the outstanding indebtedness thereunder in the event of a change of control of the Company, as defined in the respective agreements. Each of the indentures provides that if there is a change of control of the Company, as defined in the respective indenture, we are required to make an offer to each holder to repurchase all or any part of the 12¾% Senior Secured Notes or the 9.75% convertible senior unsecured subordinated debentures, as the case may be, at 101% of the aggregate principal amount of the notes or debentures tendered for repurchase, plus accrued and unpaid interest. In the event of a change of control, as defined under the Revolving Credit Facility Agreement, all obligations under the Revolving Credit Facility will become immediately due and payable. If the change of control event occurs in one or more of these agreements, we may not have adequate financing available to meet the resulting payment obligations.

We continually evaluate our capital needs and compare them to our capital resources. To execute our operational plans, particularly our drilling plans in East Texas and Australia, additional funds will be needed for acreage acquisition, seismic and other geologic analysis, drilling, undertaking completion activities and for general corporate purposes. We may have to significantly reduce our drilling and development program if our internally generated cash flow from operations and cash flow from financing activities are not sufficient to pay debt service, corporate overhead and expenditures associated with our projected drilling and development activities. We expect to fund these expenditures from internally generated cash flow, cash on hand, sales of assets and the issuance of additional debt or equity. We may also attempt to balance future capital expenditures through joint venture development of certain properties with industry partners. We cannot be certain that future funds will be available to fully execute our current business plan.

Our 2008 capital expenditures under our current business plan are estimated to total approximately $65.4 million, of which $43.4 million is estimated to be spent on unconventional natural gas and oil exploration and development operations in East Texas, $7.4 million is estimated to be spent on CBM projects and additional projects in the United States and $14.6 million is estimated to be spent on CBM projects in Australia. Based on our current budget, we have sufficient capital, together with internally generated cash flow, to fund our exploration and development activities in East Texas and Australia for 2008 and a significant portion of 2009’s projected capital needs in excess of the next 12 months.

Our cash flow and ability to raise capital are highly dependent upon natural gas pricing. A material decrease in current and projected natural gas prices could impact our ability to fund future activities, impair our ability to raise additional capital on acceptable terms and result in a financial covenant default under the 12  3 / 4 % Senior Secured Notes, resulting in mandatory principal reduction under certain conditions.

 

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In the third and fourth quarters of 2007, we entered into two costless collar transactions with counterparties. The first transaction covers a notional volume of 2,000 MMBtu per day or approximately 0.8 Bcf of natural gas production for the year 2008 with a $5.50 per MMBtu floor and a $7.50 MMBtu ceiling price that represent hedge prices at Inside FERC Colorado Interstate Gas Rocky Mountains (“CIG”). The second transaction covers a notional volume of 5,000 MMBtu per day or approximately 1.8 Bcf for the year 2008 with a $6.75 per MMBtu floor and a $8.00 MMBtu ceiling price that represent hedge prices at East-Houston-Katy—Houston Ship Channel (“HSC”). The volume hedged as of December 31, 2007 represents approximately 43% of 2008 projected production, as estimated by our third party reservoir engineer at December 31, 2007.

In January 2008, we hedged an additional 5,000 MMBtu per day of our Texas production at HSC prices between $7.00 per MMBtu and $8.88 per MMBtu for February 2008 through December 2008 and hedged 800 MMBtu per day of natural gas of our Powder River Basin production at CIG prices between $6.00 per MMBtu and $7.90 per MMBtu for February 2008 through December 2008. Additionally in February 2008, we hedged 5,000 MMBtu per day of our Texas production at HSC prices between $8.00 per MMBtu and $9.30 per MMBtu for January 2009 through December 2009. All 2008 hedges were costless collars.

Covenants in our 12  3 / 4 % Senior Secured Notes Indenture and our Revolving Credit Facility Agreement restrict us from hedging more than 75% of the projected production from proved developed producing reserves.

At December 31, 2007, we were in compliance with all debt covenants.

Off Balance Sheet Arrangements

As of December 31, 2007, we had no off balance sheet arrangements. We have no plans to enter into any off balance sheet arrangements in the foreseeable future.

Contractual Obligations

The following table summarizes our future contractual obligations under these arrangements as of December 31, 2007:

 

     Total    Less
Than 1 Year
   1-3 Years    3-5 Years    More
Than 5 Years
     (in thousands)

Maturities on long-term debt, including related current portion (1)

   $ 133,250    $ —      $ 33,250    $ 100,000    $ —  

Interest on long-term debt

     67,934      16,008      28,540      23,386      —  

Office lease (2)

     582      205      377      —        —  

Drilling contract (3)

     12,060      6,300      5,760      —        —  

Operating leases and other (4)

     25      8      17      —        —  
                                  

Total

   $ 213,851    $ 22,521    $ 67,944    $ 123,386    $ —  
                                  

 

(1)

These amounts represent the principal balances that will become due on our 12  3 / 4 % Senior Secured Notes, subordinated unsecured notes payable and convertible senior debenture.

(2) Office lease obligation expires October 31, 2010.
(3) Represents minimum rates under a three year drilling contract commitment requiring minimum fees per year, net of advance payments.
(4) Represents operating lease payments for various office equipment.

We maintain a reserve for cost associated with the retirement of tangible long-lived assets. At December 31, 2007, our reserve for these obligations totaled $4.4 million for which no contractual commitment exists. Information about this reserve is set forth in Note 2—Summary of Significant Accounting Policies—Asset Retirement Obligation to our consolidated financial statements, which begin on page F-1.

 

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We have employment agreements with our Chief Executive Officer, Chief Financial Officer and Chief operating Officer, which obligate us to pay a specified level of salary, target bonus and certain other payments and reimbursements to them during their employment and in the event of termination or change of control. Information about such payments is set forth in Item 11, “Executive Compensation”.

Commitments

During 2006, we entered into an agreement with a drilling contractor to provide contracted drilling services in the Hilltop area of East Texas for a three-year period at agreed upon day rates. The Company made advance payments totaling $2.0 million prior to drilling rig delivery in November 2006. The advance payments are being amortized over the three-year term of the agreement. The Company is required to pay the drilling contractor a minimum of $6.3 million per year in drilling day rate fees, net of the amortization of the advance payments, during the three-year term of the agreement commencing November 2006.

In March 2008, we entered into formal agreements with ETC Texas Pipeline, Ltd. (“ETC”) for the gathering, treating, purchase and transportation of our natural gas production from Hilltop area of East Texas. These agreements are effective September 1, 2007 and have a term of 10 years. ETC currently provides us 50 MMcfd of treating capacity and 120 MMcfd of gathering capacity. We have the right to request ETC build, at their cost, up to 150 MMcfd of treating and gathering capacity during the term of the agreement, provided that our production equals 85% of the then existing treating and gathering capacity for a 30 day period. We may at any time elect to have our treating and gathering capacity increased subject to cost indemnifications to ETC. Additional treating and gathering capacity requests must be in at least 25 MMcfd and 5 MMcfd increments, respectively. In addition, we must furnish to ETC information that reasonably demonstrates that our projected production for the five years after expansion is sufficient to warrant the costs to create the expanded treating and gathering capacity. The incremental volume increases in treating and gathering capacity shall be subject to marginal increases in treating fees. Pursuant to the agreements, we have access up to 150 MMcfd of firm transportation on ETC’s system or the pipelines of its affiliates or subsidiaries from the tailgate of the treating facility to Katy Hub. We have the option to sell and ETC has the obligation to buy, up to 150 MMcfd of our Hilltop production at delivery points upstream of ETC’s gathering and treating facilities. We do not have an obligation to deliver to ETC volumes in excess of 150 MMcfd, but should ETC elect to purchase such excess volumes, purchases will be subject to the treating and gathering expansion terms set forth in the agreements.

Registration Obligation and Penalties

On November 29, 2007, Gastar USA, a wholly owned subsidiary of Gastar Exploration Ltd., sold $100 million aggregate principal amount of 12  3 / 4 % Senior Secured Notes at an issue price of 99.50%. Gastar USA is obligated to prepare and file with the SEC within 150 days of the issue date of the 12  3 / 4 % Senior Secured Notes, or April 27, 2008, a registration statement to exchange the 12  3 / 4 % Senior Secured Notes for registered, publicly tradable notes that have substantially identical terms as the 12  3 / 4 % Senior Secured Notes. Gastar USA is to use its best efforts to cause the registration statement to be declared effective within 240 day of the issue date of the 12  3 / 4 % Senior Secured Notes, or July 24, 2008. Gastar USA has agreed to offer exchange notes in exchange for the 12  3 / 4 % Senior Secured Notes as soon as is practicable after the registration statement has become effective, unless prohibited by law or SEC policy, and to file a shelf registration statement for the resale of the 12  3 / 4 % Senior Secured Notes if Gastar USA cannot consummate the exchange offer within 290 days of the date of the issuance of the 12  3 / 4 % Senior Secured Notes, or September 12, 2008, and in certain other circumstances. In the event Gastar USA fails to meet its registration obligations as set forth above, Gastar USA has agreed to pay liquidated damages to the holders of the 12  3 / 4 % Senior Secured Notes in the form of additional cash interest payments on the 12  3 / 4 % Senior Secured Notes equal to 0.25% per annum for the first 90-day period, increasing to a maximum of 0.50% per annum for each subsequent 90-day period.

 

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New Accounting Pronouncements

Fair Value Measurements.     In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157 , “Fair Value Measurements” (“SFAS No. 157”), which addresses how companies should measure fair value when companies are required to use a fair value measure for recognition or disclosure purposes under US GAAP. As a result of SFAS No. 157 there is now a common definition of fair value to be used throughout US GAAP. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. The FASB also has issued Staff Position FAS 157-2 (“FSP No. 157-2”), which delays the effective date of SFAS No. 157 for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. The Company does not expect the adoption of SFAS No. 157 or FSP No. 157-2 to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

Non-controlling Interests in Consolidated Financial Statements.     In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of Accounting Research Bulletin No. 51” (“SFAS No. 160”), which improves the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. The Company does not expect the adoption of SFAS No. 160 to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

Business Combinations.     In December 2007, FASB issued SFAS No. 141, “Business Combinations” (“SFAS No. 141R”), which creates greater consistency in the accounting and financial reporting of business combinations. This statement is effective for fiscal years beginning after December 15, 2008. The Company does not expect the adoption of SFAS No. 141R to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

The Fair Value Option for Financial Assets and Financial Liabilities.     In February 2007, FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115” (“SFAS No 159”), which permits an entity to choose to measure certain financial assets and liabilities at fair value. SFAS No. 159 also revises provisions of SFAS No. 115 that apply to available-for-sale and trading securities. This statement is effective for fiscal years beginning after November 15, 2007. The Company does not expect the adoption of SFAS No. 159 to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

 

Item 7A. Quantitative and Qualitative Disclosure about Market Risk

Commodity Price 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, 2007, a 10% change in the prices received for natural gas production would have had an approximate $3.4 million impact on our revenues. We have entered into hedge transactions to mitigate our commodity pricing risk. See Note 9—Commodity Hedging Contracts to our consolidated financial statements, beginning on page F-1, for additional information on our hedging activities.

Interest Rate Risk

The carrying value of our debt approximates fair value. At December 31, 2007, we had approximately $133.3 million in principal amount of long-term debt, all of which was at a fixed interest rate. A 10% fluctuation in interest rates would have no impact on annual interest expense.

 

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Currency Translation Risk

Our revenues and expenses and the majority of our capital expenditures are primarily in U.S. dollars, thus limiting our exposure to currency translation risk. In 2007, our Australian activities consisted of capital expenditures totaling approximately $15.2 million. We have no plans in the foreseeable future to implement hedges or financial instruments to manage international currency changes.

 

Item 8. Financial Statements and Supplementary Data

The reports of our independent registered public accounting firms and our consolidated financial statements, related notes and supplementary information are presented beginning on page F-1.

 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

 

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2007, to ensure that information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

Notwithstanding the foregoing, because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our Company have been detected. These inherent limitations include the realities that judgments in decision making can be faulty and that breakdowns can occur because of a simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people or by management override of the control. Moreover, the design of any system of controls is also based in part upon certain assumptions about the likelihood of future events.

Management’s Report on Internal Control over Financial Reporting

Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed under the Exchange Act is accumulated and communicated to our management on a timely basis to allow decisions regarding required disclosure. Under the supervision and with the participation of our management, including our chief executive officer, chief financial officer, and chief accounting officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2007 based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Our internal control over financial reporting includes policies and procedures that (1) pertain to maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets;

 

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(2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of our management and board of directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of assets that could have a material effect on the financial statements.

Due to its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable, not absolute, assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate as a result of changes in conditions or deterioration in the degree of compliance.

Based on the assessment, our management has concluded that our internal control over financial reporting was effective as of December 31, 2007 and provides reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally accepted accounting principles. The results of management’s assessment were reviewed with the Audit Committee of our Board of Directors.

Our internal control over financial reporting has been audited by BDO Seidman, LLP, an independent registered public accounting firm, as stated in their report which is included herein.

 

/s/    J. R USSELL P ORTER             /s/    M ICHAEL A. G ERLICH        
J. Russell Porter     Michael A. Gerlich
Chairman, President and Chief Executive Officer     Vice President and Chief Financial Officer
March 17, 2008     March 17, 2008

Changes in Internal Control over Financial Reporting

During the fourth quarter of 2007, there were no changes in our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

Gastar Exploration Ltd.

Houston, Texas

We have audited Gastar Exploration Ltd.’s (the “Company”) internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Criteria”). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A, “Management’s Report on Internal Control over Financial Reporting.” Our responsibility is to express an opinion on the effectiveness of internal control over financial reporting of the Company based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Gastar Exploration Ltd. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO Criteria .

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Gastar Exploration Ltd. and subsidiaries as of December 31, 2007 and 2006 and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007 and our report dated March 14, 2008 expressed an unqualified opinion thereon.

/s/ BDO Seidman, LLP

Dallas, Texas

March 14, 2008

 

Item 9B. Other Information

None.

 

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PART III

 

Item 10. Directors, Executive Officers and Corporate Governance

Directors, Executive Officers and Certain Other Officers

Our directors, executive officers, who are also referred to as “named executive officers”, and certain other significant employees and their ages as of March 10, 2007 are as follows:

 

Name

   Age   

Position

J. Russell Porter*

   46   

Chairman, President, Chief Executive Officer and Director

Michael A. Gerlich*

   53   

Vice President and Chief Financial Officer

Jeffery C. Pettit*

   50   

Vice President and Chief Operating Officer

Henry J. Hansen

   52   

Vice President of Land

Frederick E. Beck, PhD

   48   

Vice President of Drilling

R. David Rhodes

   49   

Vice President of Completion and Production

Sara-Lane Sirey

   39   

General Corporate Canadian Counsel and Corporate Secretary

Abby F. Badwi

   61   

Director

Robert D. Penner

   63   

Director

John M. Selser Sr.

   49   

Director

 

* Named executive officer.

J. Russell Porter has been a member of our Board of Directors and has served as our President and Chief Executive Officer since February 2004 and was appointed Chairman of the Board in August 2006. From September 2000 to February 2004, he served as Chief Operating Officer and as an officer of GeoStar Corporation. Mr. Porter has an energy focused background, with approximately 17 years of natural gas and oil exploration and production experience and five years of banking and investment experience specializing in the energy sector. 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. He currently is a director of Caza Oil & Gas, Inc., a publicly traded exploration and development company listed on the Toronto Stock Exchange and the London AIM exchange. Mr. Porter holds a Bachelor of Science 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 us in May 2005, as Vice President and Chief Financial Officer. Mr. Gerlich has over 27 years of natural gas and oil accounting and finance experience. From 1994 until joining us, Mr. Gerlich served as Senior Vice President—Accounting and Finance for Calpine Natural Gas L.P., formerly known as Sheridan Energy, Inc., where he served 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 Bachelor of Business Administration degree in Accounting.

Jeffery C. Pettit joined us in August 2007, as Vice President and Chief Operating Officer. Mr. Pettit has over 28 years of natural gas and oil operational experience. Prior to joining us, Mr. Pettit was General Manager-Gulf Coast Operations and Engineering with Dominion E&P. He joined Dominion in 2001 and held positions as Joint Interest Manager and General Manager—Coalbed Methane. Previous to his service at Dominion, Mr. Pettit worked as a private engineering consultant for several independent oil and gas companies. During the twenty year period from 1979 until 1999, his employment included various operations, acquisitions, and reservoir engineering management positions with Burlington Resources, LL&E, Inexco Oil Company and Pennzoil. Mr. Pettit holds a Bachelor of Science degree in Petroleum Engineering from Mississippi State University.

 

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Henry J. Hansen joined us in September 2005, as Vice President of Land. Mr. Hansen has over 28 years of land management experience. Prior to joining us, Mr. Hansen was Rocky Mountain Land Manager with El Paso Corporation from 1999 until January 2003. He returned to El Paso Corporation in June 2004, where he was senior landman until joining Gastar in September 2005. Mr. Hansen graduated from the University of Texas at Austin, Texas with a Bachelor of Business Administration in Petroleum Management.

Frederick E. Beck, PhD joined us in April 2002, as Vice President of Drilling. Dr. Beck has over 25 years of diversified experience in the natural gas and oil business. He has held positions with a major operator as a drilling engineer, drilling supervisor and as an assistant professor of petroleum engineering at the New Mexico School of Mines. From 1996 and prior to joining us as Vice President of Operations, Dr. Beck was Vice President of the turnkey drilling division of Nabors Drilling USA LP. Dr. Beck holds a Bachelor of Science degree in Geology, Master of Science degree in Petroleum Engineering and Doctor of Philosophy Degree in Petroleum Engineering, all from Louisiana State University in Baton Rouge, Louisiana.

R. David Rhodes joined Gastar in March 2006, as Vice President of Completion and Production. Mr. Rhodes has over 25 years of petroleum engineering experience, focused primarily in the supervision and management of completion and production operations. Prior to joining Gastar, he managed Oil & Gas Operations and Consulting, Inc., an independent consulting firm he established in May 2001, where he worked as a petroleum engineering consultant for numerous natural gas and oil operators including Gastar. Mr. Rhodes continues to maintain his relationship with Oil & Gas Operations and Consulting, Inc. From 1981 to 2001, Mr. Rhodes held various engineering and management/supervisory positions at Getty Oil Company and Marathon Oil Company (formerly Texas Oil & Gas Company). His last position was Operations Manager for East Texas and Northern Louisiana. Mr. Rhodes holds a Bachelor of Science degree in Petroleum Engineering from Louisiana Tech University.

Sara-Lane Sirey, LLB is an attorney in private practice, 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, Alberta, Canada, becoming a partner in 1999. Specializing in 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.

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 of experience in the exploration, development and production of natural gas and oil fields in North America, South America, Asia, Europe and the Middle East. He currently is Chief Executive and Director of Bankers Petroleum, a Canadian public exploration and production company listed on the TSX and London AIM Exchange with operations in Europe and the USA. From July 2005 to September 2007, he was President, Chief Executive Officer and director of Rally Energy Corp., a public Canadian natural gas and oil company listed on the TSX and the Frankfurt Stock Exchange with operations in Egypt, Pakistan and Canada. Prior to joining Rally Energy, he was the President of Corrundum Energy Ltd, a private natural gas and oil investment and advisory firm from 2003 until 2005. From 2000 until 2003, he was President and CEO of Geodyne Energy Inc., a natural gas and oil venture publicly traded on Canada’s TSX Venture Exchange. Mr. Badwi has been an officer of several Canadian public and private companies, including President and Chief Operating Officer of Carmanah Resources Ltd., a Calgary, Alberta-based company with oil holdings in Canada, Indonesia and Venezuela, and Vice President International Exploration of Sceptre Resources Limited, an natural gas and oil exploration and production company. He is currently a director of Sustainable Energy Technologies Ltd. and Fairmount Energy Inc., both listed on Canada’s TSX Venture Exchange. Mr. Badwi holds a Bachelor of Science degree in petroleum geology from the University of Alexandria, Egypt.

 

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Robert D. Penner became a member of our Board of Directors effective July 16, 2007. Mr. Penner retired from his position as a senior partner with KPMG in 2004, after a career of advising public and private clients on tax and accounting matters for almost 40 years. He currently serves on the Board of Directors for Corridor Resources Ltd, Storm Cat Energy Corporation, Sustainable Energy Technologies Ltd., Terra Energy Corp. and Unbridled Energy Corporation as well as serving on the Board of Directors or as Executor/Trustee for several private companies and family trusts.

John M. Selser Sr. became a member of our Board of Directors effective March 30, 2007. He has been a partner at Maple Leaf Partners, a Baton Rouge, Louisiana based hedge fund since 2003. From 1992 to 2003, Mr. Selser was an energy equity analyst for several sell-side firms. From 1984 to 1991, Mr. Selser was a petroleum engineer for major oil companies in various domestic drilling, production and reservoir engineering assignments. Mr. Selser holds a Bachelor of Science in both Civil Engineering and Petroleum Engineering from Louisiana State University, Baton Rouge, Louisiana and a Masters of Business Administration from Tulane University, New Orleans, Louisiana.

Each of our directors holds office until the next annual meeting of shareholders or until the director resigns or is removed by actions of the board. Of our directors, Messrs. Porter and Selser are citizens of the United States, while Messrs. Badwi and Penner are citizens of Canada. There are no family relationships between any of our directors or executive officers.

Section 16 Reporting

Section 16(a) of the Exchange Act requires the Company’s directors and officers and persons who own more than 10% of a registered class of the Company’s equity securities to file reports of ownership and changes in ownership with the SEC. Directors, officers, and greater-than-10% stockholders are required by SEC regulations to furnish the Company with copies of all Section 16(a) forms they file. Based solely on review of information furnished to the Company, the Company believes that all Section 16(a) filing requirements applicable to its directors, officers, and greater than 10% beneficial owners were complied with during the year ended December 31, 2007.

Code of Ethics

We adopted a Code of Ethics on December 15, 2005. A copy of our Code of Ethics for all employees was filed as an exhibit to our Registration Statement on Form S-1/A on December 22, 2005 and is available on our website at www.gastar.com . A copy of our Code of Ethics will be provided to any person without charge, upon request. Such requests should be directed to J. Russell Porter, President and Chief Executive Officer, 1331 Lamar Street, Suite 1080, Houston, Texas 77010.

Shareholders or other interested parties may send communications to the Board of Directors by writing through the Secretary of the Company at 1331 Lamar Street, Suite 1080, Houston, Texas 77010. The Secretary will forward to the directors all communications that, in his or her judgment, are appropriate for consideration by the directors. Comments or complaints relating to our accounting, internal accounting controls or auditing matters will also be referred to members of the Audit Committee. The Audit Committee has procedures for (a) receipt, retention and treatment of complaints received by us regarding accounting, internal accounting controls, or auditing matters and (b) the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters. The “Whistleblower” procedure adopted by the Audit Committee is available on our website at www.gastar.com .

Audit Committee

We have a separately-designated standing Audit Committee, which currently is comprised of Messrs. Badwi, Penner (chairman and financial expert) and Selser. After reviewing the qualifications of the

 

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current members of the Audit Committee, the Board of Directors has determined that all current Audit Committee members are “independent”, as that concept is defined in Section 10A of the Exchange Act, and the applicable rules of the American Stock Exchange. The Board of Directors also determined that all current Audit Committee members are financially literate and that Mr. Penner is a “financial expert” under the applicable rules of the Exchange Act. In accordance with its Terms of Reference, the Audit Committee examines and reviews on behalf of the Board of Directors, internal financial controls, financial and accounting policies and practices, related party transactions and the form and content of financial reports and statements. The Audit Committee is responsible for the hiring, overseeing and terminating the independent accountants engaged to prepare any audit or issue any audit report, and the work of the external auditors. The Chief Financial Officer attends the meetings of the Audit Committee by invitation.

On March 15, 2007, we notified the American Stock Exchange that we were not in compliance with the American Stock Exchange Company Guide Rule 121(B)(2)(a), which requires that each listed company must have, and certify that it has and will continue to have, an audit committee of at least three independent members. As a result of an independent member of our Audit Committee not standing for reelection at our 2006 annual meeting of shareholders, the Audit Committee was left with two independent members, one of whom remains designated as its “financial expert”. On July 16, 2007, we announced that Mr. Robert D. Penner had been appointed a director and a member of the Audit Committee, bringing us into compliance with the American Stock Exchange Company Guide Rule.

Notwithstanding our temporary non-compliance with the American Stock Exchange rule regarding the number of independent directors serving on the Audit Committee, at all times since January 4, 2006, the date we first became listed and subject to the reporting requirements of the Exchange Act, as amended, our Audit Committee has consisted solely of directors meeting the independence requirements of the American Stock Exchange and Section 10A of the Exchange Act.

 

Item 11. Executive Compensation

Compensation Discussion and Analysis

The following Compensation Discussion and Analysis explains our compensation objectives, philosophy and practices with respect to our Chief Executive Officer, Chief Financial Officer and Chief Operating Officer, who are referred to as named executive officers. These individuals are our only executive officers.

Compensation Philosophy

Our compensation programs for our named executive officers are designed to achieve the following objectives:

 

   

Attract and retain highly talented individuals who will engage in behavior essential to our success;

 

   

Motivate and reward employee performance that is critical to our success;

 

   

Align the interests of our named executive officers and our shareholders by motivating our named executive officers to increase shareholder value and rewarding them based on operational and financial success and when shareholder value increases; and

 

   

Balance annual cash payments and longer term equity compensation.

Our executive compensation is structured to achieve these goals through our mix of short-term cash payments and long-term equity compensation.

 

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Elements of Executive Compensation and Rationale

There are three key elements to our compensation: base salary, annual cash bonus awards and stock-based compensation. We believe that a combination of these three elements balances rewards for current performance and longer term corporate objectives as measured, among other things, by operational successes, common share performance and creation of shareholder value. The terms of the named executive officers’ employment, including their compensation and other benefits, are set forth in employment agreements, described below.

Role of the Remuneration Committee, its Consultant and Management

Executive compensation is the responsibility of the Remuneration Committee (for purposes of this analysis, the “Committee”). The Committee operates under a written charter, or the “Terms of Reference”, adopted by the Board of Directors. Abby F. Badwi, Robert D. Penner and John M. Selser Sr. are members of the Board of Directors and members of the Committee. Mr. Badwi is the Committee Chairman. Each member of the Committee qualifies as an independent director under the American Stock Exchange listing standards and under the Exchange Act.

The aim of the Committee is to award and compensate officers and employees in a manner which provides incentives for the enhancement of shareholder value, for the successful implementation of the Company’s business plan and for continuous improvement in corporate and personal performance. The compensation program is based on a pay-for-performance philosophy.

The Committee reviews and recommends the compensation philosophy and guidelines for the Company, which include reviewing the compensation philosophy and guidelines (a) for executive management, for recommendation to the Board for its consideration and approval, and (b) relating to all employees, including annual salary and incentive policies and programs, and material new benefit programs or material changes to existing benefit programs.

During 2007, the Committee engaged Thomas J. Reno & Associates, Inc. (“TJR”), a consulting firm experienced in executive compensation, which has access to national compensation surveys and our compensation information. TJR’s responsibilities include”

 

   

Providing recommendations on compensation based on review of the compensation of our peer group (as described below);

 

   

Gathering and analyzing publicly available proxy data from the peer group and other peer group data;

 

   

Analyzing pay survey data and analyses provided by our management;

 

   

Reviewing and advising on the performance measures to be used in bonus formulas and equity awards; and

 

   

Reviewing and advising on target bonus levels, actual year end bonus calculations and the design and size of equity awards.

These peer companies reviewed by TJR included Abraxas Petroleum Corp., Exploration Company of Delaware, Gasco Energy Inc., GMX Resources Inc., Harvest Natural resources Inc., NGAS Resources Inc., Toreador Resources Corp., Transmeridian Exploration Inc. and Warren Resources Inc. TJR reviewed the amount or form of executive and director compensation, as well as periodic detailed analyses of peer group executive salaries, cash bonus awards and other incentive compensation bonus awards and other incentive compensation awards, such as stock options and restricted common stock grants. This information is used by the Committee to insure that base salaries and other benefits are reasonable and competitive with those offered by our peer group to their executives.

 

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Our Chief Executive Officer also plays an important role in the executive compensation process and is closely involved in assessing the performance of our named executive officers and making recommendations regarding base salary, bonus targets, performance measures and weighting and equity compensation for these executive officers. The compensation of our Chief Financial Officer and Chief Operating Officer is determined by the Committee, after receiving the recommendations of the Chief Executive Officer as to what he considers to be fair compensation for our named executive officers. The recommendations are based on an assessment of the Chief Financial Officer’s and Chief Operating Officer’s responsibilities and performance, the Company’s performance and the market in which the Company competes for executive talent. The Chief Executive Officer attends those portions of the meetings of the Committee that are related to the Chief Financial Officer’s and Chief Operating Officer’s compensation. The compensation of our Chief Executive Officer is determined by the Committee. In determining the compensation of the Chief Executive Officer, the Committee takes into account the Chief Executive Officer’s responsibilities and performance, the Company’s performance and the market in which the Company competes for executive talent. The Chief Executive Officer does not attend any meetings related to his compensation.

Our Chief Financial Officer also plays an important role in our executive compensation process. Our Chief Financial Officer makes recommendations to the Committee regarding the structure of the annual cash bonus awards program and the size of such awards. These recommendations are drawn from our Chief Financial Officer’s previous work experience and informal surveys of the annual cash bonus programs of other similar sized companies and other oil and natural gas companies.

Benchmarking of Compensation

When making compensation decisions, we also look to the compensation of our named executive officers relative to the compensation paid to similarly-situated executives at other organizations that are similar in size and operations to us. During 2007, TJR provided us with competitive compensation data from our peer group as well as business and technical considerations. In 2007, we used three primary resources to identify competitive compensation relevant to our named executive officers:

 

   

TJR;

 

   

2007 U.S. Energy Compensation Survey; and

 

   

SEC disclosure data for similarly sized organizations within the natural gas and oil industry.

Third-party survey data, such as that provided by TJR and information from other resources and industry contacts, is considered when evaluating external competitiveness. We use this data to ensure that we are maintaining a level of compensation that is both commensurate with our size and sufficient to retain personnel we consider essential. In reviewing comparative data, we do not engage in benchmarking for the purpose of establishing compensation levels relative to any predetermined point. In the Committee’s view, third-party survey data provides insight into external competitiveness but is not an appropriate single basis for establishing compensation levels. This is primarily due to the differences in the size of comparable companies and the lack of sufficient appropriate matches to provide statistical relevance. Our preference is that performance, rather than third party survey data, should drive executive compensation. The Committee seeks the input of our Chief Executive Officer in evaluating the performance of all of our executive officers, excluding himself. Our Chief Financial Officer assists in the gathering of information regarding the employment market assessment.

In the processes used by the Committee to establish and adjust executive compensation levels, third party-survey data is considered, along with performance, experience and the potential of the individual to contribute to the Company’s operations and growth. The Committee can exercise both positive and negative discretion in relation to the compensation awards and its allocation between cash and non-cash awards. The Committee has the authority to approve, deny and suggest alternative compensation packages.

 

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Elements of Executive Compensation and Rationale

The Company entered into employment agreements with J. Russell Porter, our President and Chief Executive Officer, and Michael A. Gerlich, our Chief Financial Officer, effective February 24, 2005 and May 17, 2005, respectively. The agreements with Messrs. Porter and Gerlich set forth, among other things, annual compensation, and adjustments thereto, minimum bonus payments, termination provisions, fringe benefits, termination and severance provisions. The agreements automatically renew annually; however, they may be terminated at any time with or without cause. The Company and Jeffery C. Pettit, our Chief Operating Officer, entered into a letter agreement on August 21, 2008. The letter agreement sets forth, among other things, Mr. Pettit’s initial base salary, a guaranteed 2007 bonus, fringe benefits, such as vacation and medical insurance coverage, and severance provisions for his at will employment, which may be terminated at any time by us or Mr. Pettit with or without cause. See “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table” for additional information on employment agreement to the named executive officers.

Base Salary.     Base salary represents the fixed element of the named executive officers’ cash compensation. The base salary reflects economic consideration for each individual’s level of responsibility, expertise, skills, knowledge, experience and performance. Base salaries for our named executive officers are reviewed annually. Each of our named executive officer’s initial annual salary is set for the terms of their respective employment agreement but may be adjusted upward or downward at each anniversary date of each officer’s employment at the discretion of the Committee. The base salary amounts for Messrs. Porter and Gerlich have been set at $450,000 and $275,000 respectively. Mr. Pettit’s letter agreement with us set his initial base salary at $285,000. A description of the material terms of each named executive officer’s employment agreement is provided in “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table—Employment Agreements”.

In 2007, the Committee made no changes to the base salary amounts for any of our named executive officers, based on the Committee’s determination that the existing base salaries were competitive and appropriate in light of the named executive officers’ tenure with the Company and the overall level of corporate activity.

Annual Cash Bonus Awards.     Our cash bonus awards reflect our philosophy to pay for performance. These awards provide our named executive officers, as well as our other employees on the same basis, with an opportunity to earn an annual cash bonus based on an evaluation of individual performance and the Company achieving certain operational and financial performance targets. At the beginning of each year, the Committee approves a target cash bonus pool, which equals the sum of a bonus target percentages of each employee times each employee’s annual salary. The targeted bonus percentages for named executive officers was determined using the experiences of the members of the Committee, the review of cash bonus awards of named executive officers with other companies, many of which have substantially more resources to evaluate such matters, and on informal surveys with other companies. At the end of each year, the Company’s performance is evaluated against certain specific operational and financial target criteria. Each criterion is given a certain weighting, with a majority of the weighting allocated to operational factors. In developing the appropriate target criteria and their respective weightings, the Committee analyses the relative importance of each of the target criteria to our business strategy for the upcoming fiscal year. Criteria and weightings used in 2007 were:

 

   

Achieving a target average annual production per day for the year (20%);

 

   

Achieving a target total Company proved reserves (20%);

 

   

Achieving specific Texas average (per Mcfe) finding and development costs and controllable lifting costs (20%);

 

   

Achieving specific overall per Mcfe average cash general and administrative expense (5%);

 

   

Achieving specific level of operating cash flow (25%); and

 

   

Accomplishing certain financing goals during the year (10%).

 

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Performance above or below the targeted criteria results in a calculated increase or decrease in the cash bonus pool. Certain minimum targets are also established for the individual criteria which, if not met, results in no bonus being earned for that criterion. At the end of the year, an approved bonus pool is calculated based on the bonus pool criteria accomplishments. The amount of the calculated bonus pool is subject to adjustment and final approval by the Committee. As a result of our 2007 operational and financial performance, we surpassed all of the performance targets except one operational criterion. This would have resulted in a calculated bonus pool of an amount equal to 250% of the target cash bonus pool. In its discretion, the Committee reduced the calculated bonus pool to an amount equal to 150% of the target cash bonus pool.

For 2007, the Committee determined that Mr. Porter’s target cash bonus would be 50% of his annual compensation based on the reasons described above. As a result of our operational and financial performance, he was awarded a cash bonus of $337,500, or 75% of his base salary in 2007, which is equal to 150% of his target bonus. He received an amount based on the same formula applicable to all employees of 1.5 times targeted cash bonus. His 2007 bonus reflected his leadership in raising significant debt and equity capital to finance our expanded exploration activities in East Texas and Australia, as well as the Company meeting and exceeding the operational and financial targets described above.

For 2007, the Committee determined that Mr. Gerlich’s target cash bonus would be 35% of his annual compensation based on the reasons described above. As a result of our operational and financial performance, he was awarded a cash bonus of $145,000, or 53% of his base salary in 2007, which is equal to 150% of his target bonus. He received an amount based on the same formula applicable to all employees of 1.5 times targeted cash bonus. His 2007 bonus recognized his financial skills used to successfully raise significant debt and equity capital to finance our expanded exploration activities in East Texas and Australia, providing the leadership in the successful completion of the Sarbanes Oxley compliance process, including IT compliance, as well as the Company meeting and exceeding the operational and financial targets described above.

For 2007, the Committee determined that Mr. Pettit’s target cash bonus would be 25% of his annual compensation based on the reasons described above. In 2007, he was awarded a cash bonus of $40,000, or 38% of his base salary, pro rated for the period he was employed by us during the year. He received an amount based on the same formula applicable to all employees of 150% of targeted cash bonus. His 2007 bonus recognized his contribution to the overall improvement in operational activities since becoming our Chief Operating Officer, as well as the Company meeting and exceeding the operational and financial targets described above.

In 2007, a significant factor in determining the 150% of multiplier to calculate the level of cash bonus awards was the Company’s substantially improved exploration and operational results, as compared to those of 2006, and the substantial increase in year end proved reserves.

Cash Retention Payment Award .    The Company is involved in a number of litigation matters, where an adverse ruling could have a material adverse effect on us. Retention of our named executive officers and all other employees has become a meaningful consideration in our overall compensation package. As a result of the uncertainties created by this situation, the Board of Directors at the Committee’s recommendation approved cash retention payment awards for the named executive officers, as well as all other employees. Each named executive officer and other current employees of the Company who are still employed by the Company on January 31, 2009 will receive a cash retention payment equal to their target bonus. The cash incentive bonus awards for Messrs. Porter, Gerlich and Pettit are calculated to be $225,000, $96,250 and $71,250.

Stock-based Compensation.     We believe that equity compensation is the most effective means of linking compensation provided to our named executive officers with long-term operational success and increases in shareholders’ value. The Board of Directors has discretionary authority to determine granting and vesting periods of stock option and restricted common share grants. We use stock-based compensation as a long-term vehicle because we believe:

 

   

Stock-based compensation align the interests of named executive officers and our other employees with those of the shareholders;

 

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The vesting period incorporated into stock-based compensation fosters a longer term perspective necessary for staff retention, stability and continuity; and

 

   

Stock-based compensation helps to provide a longer term balance to our overall compensation program.

Historically, we used stock options as the equity compensation vehicle. In mid-2007, we began using grants of restricted common shares to employees as a compensation vehicle, rather than stock options. This change occurred in response to the Committee’s judgment that to retain and attract qualified employees we needed a more definable deferred monetary incentive than was being provided by stock option grants. Currently, restricted common shares are granted to new hires at the time of employment and to all others, including our named executive officers, in the first half of the year, as determined by the Committee. The 2007 grants of restricted common shares vest one-third on the second, third and fourth anniversaries of the grant. This vesting schedule was based on the Chief Executive Officer’s belief that a vesting schedule that delayed the initial vesting of shares until the second anniversary of the grant provides more incentive for retention of employees than might be provided by a shorter initial vesting period.

Although we do not anticipate using stock option grants for employees in the future, we have utilized stock option grants as the equity compensation vehicle for our directors, although this may change in the future.

In July 2007, Messrs. Porter and Gerlich received a restricted common share grant for an aggregate of 225,000 and 137,500 of our restricted common shares, respectively. The restricted common shares granted to Messrs. Porter and Gerlich were part of a larger annual grant of restricted common shares to employees designed to retain and provide additional employee incentives.

The number of restricted common shares is calculated by multiplying 50% times the employee’s base salary. For 2007, TJR recommended that the target bonus percentage be 100% of base salary based on their review of the compensation practices of our peer companies. The Committee determined that the target bonus percentage for 2007 would be 50% of each employee’s base salary. In making this determination, the committee also considered other factors, such as Mr. Porter’s leadership and his success during the year in raising significant debt and equity capital to finance our expanded exploration activities in East Texas and Australia, Mr. Gerlich’s contribution during the year in raising significant equity capital to finance our expanded exploration activities in East Texas and Australia and the Company’s successful completion and compliance with the Sarbanes Oxley Act, and Mr. Pettit’s guidance in the overall improvement in our operational activities.

Mr. Pettit joined us as Chief Operating Officer in August 21, 2007. As a part of his employment package, Mr. Pettit received a restricted common share grant for an aggregate of 112,500 restricted common shares.

Perquisites.     The named executive officers are eligible to participate in the same comprehensive benefits as are offered to all full-time employees. Additionally, Mr. Porter’s employment agreement provides that we will pay or reimburse him up to $25,000 for his membership dues in clubs and/or organizations as are reasonable and customary for a senior executive officer and will reimburse him for the cost of a yearly executive physical examination and all required or recommended medical testing in connection with that yearly examination. During 2007, we paid, or reimbursed, Mr. Porter a total of $73,138. See footnote 3 to “Summary Compensation Table” for details of payment of perquisites to Mr. Porter in 2007.

During 2007, other than the comprehensive benefits offered to all full-time employees, neither Mr. Gerlich nor Mr. Pettit received any perquisites having a value over $10,000 in aggregate.

 

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Post Termination or Change of Control Compensation and Benefits

On March 23, 2007, our Board of Directors approved a change of control severance plan, as amended February 15, 2008, covering all employees, including the named executive officers. The purpose of the severance plan is to promote stability and continuity of management and employees in the event a change of control transaction should occur. Pursuant to the terms of their respective employment agreements and the provisions of our change of control severance plan, Messrs. Porter, Gerlich and Pettit are entitled to receive certain post termination compensation and benefits. These benefits were determined in the negotiations with each individual and were based on what the Board of Directors determined were elements of a competitive compensation arrangement at the time or as set forth in the Employee Change of Control Severance Plan. See “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table” and “Potential Payments upon Termination or Change of Control” below.

REMUNERATION COMMITTEE REPORT

Board of Directors of Gastar Exploration Ltd.

The Remuneration Committee has reviewed and discussed the Compensation Discussion and Analysis with management and based on the review and discussions referred to above, the Remuneration Committee recommends to the Board of Directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the year ended December 31, 2007 and in the Company’s proxy statement on Schedule 14A.

 

GASTAR EXPLORATION LTD.

REMUNERATION COMMITTEE

/s/    A BBY F. B ADWI        
Abby F. Badwi
/s/    R OBERT D. P ENNER        
Robert D. Penner
/s/    J OHN M. S ELSER S R .        
John M. Selser Sr.

The above Report of the Remuneration Committee of the Board of Directors does not constitute soliciting material and should not be deemed filed or incorporated by reference into any other Company filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent the Company specifically incorporates this Report by reference therein.

 

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Summary Compensation and Awards

The following table and discussion below sets forth information about the compensation awarded to, earned by or paid to our named executive officers during the years ended December 31, 2007 and 2006.

Summary Compensation Table

 

Name and Principal Position

   Year    Salary    Bonus    Option
Awards
(1)
   Restricted
Common
Shares (2)
   All Other
Compensation (3)
   Total

J. Russell Porter

   2007    $ 450,000    $ 337,500    $ 770,030    $ 89,152    $ 73,138    $ 1,719,820

Chairman, President and Chief Executive Officer

   2006    $ 450,000    $ 225,000    $ 944,655    $ —      $ 95,892    $ 1,715,547

Michael A. Gerlich

   2007    $ 275,000    $ 145,000    $ 441,507    $ 54,482    $ —      $ 915,989

Vice President and Chief Financial Officer

   2006    $ 275,000    $ 96,000    $ 583,221    $ —      $ —      $ 954,221

Jeffery C. Pettit (4)

Vice President and Chief Operating Officer

   2007    $ 104,865    $ 40,000    $ —      $ 22,558    $ —      $ 167,423

 

(1) The fair values of stock option awards are determined by using the Black-Scholes-Merton valuation model as of the date of grant, as set forth in SFAS 123R. See Note 8—Equity Compensation Plans—Determining Fair Value under SFAS 123R to our consolidated financial statements, which begins on Page F-1, for a discussion of assumptions made in the valuation of option awards. The fair value at the date of grant is amortized using the “graded-vesting method”, which recognizes compensation costs over the requisite service period for each separately vesting tranche of an award as though the award were, in substance, multiple awards. The amounts shown in these column represent the stock-based compensation expense for the years ended December 31, 2007 and 2006, prior to a 5.0% deduction for estimated forfeitures, attributable to stock options and restricted common share grants that was attributable to all stock options and restricted common shares granted to the named executive officer and outstanding during each respective year that is recognized by us in that respective year. During 2007, total fair value attributable to restricted common share grants to Messrs. Porter, Gerlich and Pettit as of the date of grant was $495,000, $203,500 and $187,875, respectively. During 2006, total fair value attributable to stock options granted to Messrs. Porter and Mr. Gerlich as of the date of grant was $1,677,646 and $1,035,262, respectively.

 

(2) Grant date fair value of restricted common share awards is equal to the closing price of our common shares on the day prior to the date of grant times the number of common shares granted. This fair value is used to determine the stock-based compensation expense, as shown in our consolidated financial statements. The amounts shown in these column represent the stock-based compensation expense for the year ended December 31, 2007 prior to a 5.0% deduction for estimated forfeitures, attributable to restricted common share grants that was attributable to all restricted common shares granted to the named executive officer and outstanding during each respective year that is recognized by us in that respective year. During 2007, total fair value attributable to restricted common share grants to Messrs. Porter, Gerlich and Pettit as of the date of grant was $281,250, $171,875 and $140,625, respectively.

 

(3) Of the $73,138 shown for Mr. Porter in 2007, $16,610 related to the rental and related utility costs for an apartment in Houston, Texas; $10,800 related to the rental of an office in Miami, Florida (our Chief Executive Officer’s city of residence); $13,569 related to the use of a rental car while in Houston; $18,821 related to airfare between Houston and Miami, $9,000 related to the Company’s contribution to Mr. Porter’s 401-K plan and the balance of $4,338 was for club dues. Each of the items was incurred by or on behalf of Mr. Porter in the ordinary course of business or for his convenience and was considered a reasonable perquisite for a senior executive officer.

 

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     Of the $95,892 shown for Mr. Porter during 2006, $19,962 related to the rental and related utility costs for an apartment in Houston, Texas; $41,264 related to the rental of an office in Miami, Florida (our Chief Executive Officer’s city of residence); and $13,274 related to the use of a rental car while in Houston. The balance of $21,392 was related to airfare between Houston and Miami, club dues, an executive health physical examination and the Company’s contribution to Mr. Porter’s 401-K plan. Each of the items was incurred by or on behalf of Mr. Porter in the ordinary course of business or for his convenience and was considered reasonable and customary perquisites for a senior executive officer.

 

     As permitted by the rules promulgated by the SEC, no amounts are shown for Messrs. Gerlich and Pettit with respect to all other compensation received in 2007 and 2006, as the total value of all perquisites and personal benefits during the year was less than $10,000 per year.

 

(4) Mr. Pettit commenced his employment with us on August 21, 2007.

The following table shows certain information about the number of restricted common shares granted to our named executive officers during the year ended December 31, 2007. There were no stock option grants to named executive officers in 2007.

Grants of Plan-Based Awards Table

For the Year Ended December 31, 2007

 

Name

   Grant
Date
   Number of
Restricted
Shares of
Stock
   Number of
Securities
Underlying
Options
   Exercise
or Base
Price of
Awards
   Grant Date
Fair Value of
Awards (1)

J. Russell Porter (2)

   07/03/07    225,000    —      $ 2.20    $ 495,000

Michael A. Gerlich (2)

   07/03/07    137,500    —      $ 2.20    $ 302,500

Jeffery C. Pettit (3)

   08/27/07    112,500    —      $ 1.67    $ 187,875

 

(1) Grant date fair value of restricted common share awards is equal to the closing price of our common shares on the day prior to the date of grant times the number of common shares granted. This fair value is used to determine the compensation expense, as shown in our consolidated financial statements.

 

(2) The 07/03/07 grant of restricted common shares to Messrs. Porter and Gerlich vest 33.3% on 07/03/09, 07/03/10 and 07/03/11.

 

(3) The 08/27/07 grant of restricted common shares to Mr. Pettit vest 33.3% on 08/27/09, 08/27/10 and 08/27/11.

Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table

The following is a narrative of our various compensation plans and the general terms of each:

2002 Stock Option Plan.     The Company’s 2002 Stock Option Plan was approved and ratified by the Company’s shareholders in July 2002. It authorizes the Company’s Board of Directors to issue stock options to directors, officers, employees and consultants of the Company and its subsidiaries to purchase a maximum of 25.0 million common shares. Stock option grant expirations vary between five and 10 years. The vesting schedule has varied from two years to four years but generally has occurred over a four-year period at 25% per year beginning on the first anniversary date of the grant. Stock options issued pursuant to the Company’s 2002 Stock Option Plan have an exercise price determined by the Board of Directors, but that exercise price cannot be less than the market price on the date immediately prior to the date of grant as reported by any stock exchange on which the Company’s common shares are listed. If a stock option granted under the Company’s 2002 Stock Option Plan expires or terminates for any reason in accordance with the terms of the Company’s Stock Option Plan, the unpurchased common shares subject to that stock option become available for other stock option grants.

 

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In April 2004, the Board of Directors amended the provisions of the Company’s 2002 Stock Option Plan to specifically incorporate a provision to provide for stock options to be exercised on a cashless basis, whereby the Company issues to the optionee the number of common shares equal to the stock option exercised, less the number of common shares which when multiplied by the market price at the date of exercise equals the aggregate exercise price for all of the common shares exercised. As of December 31, 2007, stock option grants covering the issuance of 10,173,750 common shares were outstanding under the 2002 Stock Option Plan.

2006 Gastar Long-Term Stock Incentive Plan.     On June 1, 2006, the Company’s shareholders approved the 2006 Gastar Long-Term Stock Incentive Plan. The 2006 Gastar Long-Term Stock Incentive Plan authorizes the Company’s Board of Directors to issue stock options, stock appreciation rights, bonus stock awards and any other type of award established by the Committee which is consistent with the Plan’s purposes to directors, officers and employees of the Company and its subsidiaries covering a maximum of 5.0 million common shares. The contractual life and vesting period for a grant will be determined by the Board of Directors at the time grant is awarded. The vesting period for restricted common stock grants during 2007 was over four years, with one-third vesting on the second, third and fourth anniversaries of the date of grant. As of December 31, 2007, only grants covering the issuance of 1,096,000 restricted common shares were outstanding under the 2006 Gastar Long-Term Stock Incentive Plan.

All stock options incorporate the following features:

 

   

Existing grants have a term of five or 10 years;

 

   

Grant price is not less than the closing market price on the date immediately prior to the date of grant;

 

   

Grants do not include “reload” provisions;

 

   

Repricing of options is prohibited, unless approved by the shareholders; and

 

   

Stock options vest over a period of time that is determined by the Board of Directors.

In 2006 and a portion of 2007, stock options were granted to new hires at the time of employment and to all other employees, including our named executive officers, around the time of our annual meeting of shareholders. The Board of Directors has discretionary authority to determine granting and vesting periods of stock options. Typically, vesting periods have been over a four-year period with 25% vesting on the first, second, third and fourth anniversary dates. Certain stock options granted in 2006 to our Chief Executive Officer and certain technical managers vest over two years. Other stock options granted on the same date to the Chief Financial Officer and other employees vest over three years. The stock option awards having shorter vesting periods were granted to provide additional shorter term incentive to our named executive officers, certain technical and other employees.

Pursuant to our incentive plans, the Board of Directors has designated the Remuneration Committee as the entity to administer the granting of stock options, restricted common stock grants and other forms of stock-based compensation. Grants are determined by the Committee, based on the recommendations of our Chief Executive Officer, except in the case of grants awarded to the Chief Executive Officer. In determining a grant to named executive officers, the Committee has taken into account the named executive officer’s position, the scope of his responsibilities, his ability to affect profits and shareholder value and the individual’s past and current individual performance and corporate performance.

Employee Change of Control Severance Plan.     A change of control is defined in the severance plan to mean (1) the consummation of a merger, consolidation, reorganization or other transaction whereby our shareholders retain less than 50% control, directly or indirectly, of us or the surviving company, (2) our incumbent directors cease to constitute a majority of the board of directors or (3) a sale or other disposition of all or substantially all of our assets. The change of control severance plan does not change the specific, non-change of control severance payments in place under the existing employment agreements with our named executive

 

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officers but does provide change of control severance benefits to the named executive officers only if they are greater than the severance benefits provided under the employment agreement. The change of control severance plan does not allow for any duplication of severance benefits.

For the named executive officers, the change of control severance plan provides that if a named executive officer’s employment is terminated within two years following a change of control for any reason other than (i) death, (ii) disability, (iii) by us for “cause” or (iv) by the named executive officer for other than a “good reason”, the named executive officer will receive a lump-sum payment equal to a multiple that is equal to the applicable severance period, as set forth in the change of control severance plan, times the sum of (1) his annual salary and (2) annual target bonus.

The following summarizes the severance periods and target bonus percentages for the named executive officers set forth in the change of control severance plan:

 

     Severance
Period
in Years
   Target
Bonus

Percentage
 

Chief Executive Officer

   3.00    50 %

Chief Financial Officer

   2.50    35 %

Vice President (Chief Operating Officer)

   2.00    25 %

Additionally, during the applicable severance period, named executive officers would receive reimbursement for the cost of COBRA continuation health care coverage, less the amount charged at the time of termination to the employee for their medical coverage.

If the named executive officer receives a payment or benefit that is subject to the “golden parachute” excise tax, the named executive officer will receive an additional payment under the severance plan to make him or her “whole” for that excise tax and any taxes on the additional parachute tax gross-up payment.

If the individual’s employment is terminated within six months prior to a change of control and it is reasonably shown to have been in connection with the change of control, then the change of control will be treated with respect to that employee as having occurred prior to his or her termination.

Employment Agreements.     We entered into employment agreements with J. Russell Porter, our President and Chief Executive Officer; and Michael A. Gerlich, our Chief Financial Officer, effective February 24, 2005 and May 17, 2005, respectively. The agreements with Messrs. Porter and Gerlich set forth, among other things, annual compensation, and adjustments thereto, minimum bonus payments, fringe benefits, termination and severance provisions. The agreements renew annually; however, they may be terminated at any time with or without cause. Jeffery C. Pettit, our Chief Operating Officer, entered into an employment letter agreement on August 21, 2008. The letter agreement sets forth, among other things, Mr. Pettit’s initial base salary, a guaranteed 2007 bonus, fringe benefits and severance provisions for Mr. Pettit’s, which may be terminated at any time by us or Mr. Pettit with or without cause.

Mr. Porter’s employment agreement provides that he is entitled to an annual bonus in an amount that may take the form of cash compensation, the award of stock or stock options, royalty rights or otherwise and that he shall receive an annual cash bonus equal to at least 20% of his annual base salary. The employment agreement further provides that the bonuses shall reflect not only the results of the Company’s operations and business, but his contribution as President and Chief Executive Officer.

Mr. Porter’s employment agreement also provides that his employment shall terminate (i) without notice upon his death; (ii) without notice upon his “Disability”, as defined in his employment agreement; (iii) upon six month’s written notice to us by Mr. Porter for any or no reason, with or without cause; (iv) upon one year’s written notice to Mr. Porter by us for any or no reason, with or without cause; or (v) by us without prior notice

 

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upon a showing of “Reasonable Cause”, as defined in his employment agreement. If he is terminated by us for any reason other than cause, he will receive severance pay of two years total compensation. The severance payment will consist of the payment of Porter’s W-2 compensation earned in the calendar year coincident with or immediately preceding Porter’s termination of employment, payable over the appropriate number of weeks after termination of employment (the “Severance Pay Period”) and continuation of health insurance for Mr. Porter and his family at our expense during the Severance Pay Period. If Mr. Porter dies during the Severance Pay Period, severance pay and health benefits will continue for the benefit of his eligible beneficiary during the remainder of the Severance Pay Period.

Mr. Gerlich’s employment agreement provides that the Committee may on a yearly basis, or more frequently, award Mr. Gerlich a discretionary bonus or bonuses based not only on the positive results of our operations and business, but Mr. Gerlich’s contribution as Chief Financial Officer. Such bonuses may take the form of cash compensation, the award of stock or stock options, royalty rights or otherwise. Mr. Gerlich’s employment agreement also provides that his employment shall terminate (i) without notice, upon his death; (ii) without notice, upon his “Disability”, as defined in his employment agreement; (iii) upon two month’s written notice to us by Mr. Gerlich for any or no reason, with or without cause; (iv) if there is a “change of control”, as defined in his employment agreement and that “change in control” results in a material change in the scope of Mr. Gerlich’s duties and responsibilities such that he terminates his employment; (v) upon two month’s written notice to Mr. Gerlich by us for any or no reason, with or without cause and (vi) or by us without prior notice, upon a showing of “Reasonable Cause”, as defined in his employment agreement. If he is terminated by us for any reason other than cause, he will receive severance pay of two years annual gross salary, exclusive of bonuses received, stock options granted or exercised, or other non cash compensation. The severance payment will be calculated on the basis of his then current annual salary, to be earned in Mr. Gerlich’s then current employment year coincident with or immediately preceding the notice of termination of employment, payable in equal amounts over 100 weeks (the “Severance Pay Period”). There will be continuation of health insurance for Mr. Gerlich and his family at our expense during the Severance Pay Period. If Mr. Gerlich dies during the Severance Pay Period, severance pay and health benefits will continue for the benefit of his eligible beneficiary during the remainder of the Severance Pay Period.

Mr. Pettit’s employment agreement provides that he or us may terminate his employment and any time, with or without cause. If he is terminated by us for cause (as defined in his employment agreement), he will not be eligible for severance or other compensation; except for, accrued annual salary to the date of termination. If he is terminated by us without cause during his first two years, he will receive 1.0 times his annual salary plus stock options or restricted common shares vested prior to the date of termination. If he is terminated by us without cause after his second year of employment, he will receive 1.5 times his annual salary plus stock options or restricted common shares vested prior to the date of termination. Any severance or other compensation shall be paid over the termination period. We may terminate Mr. Pettit’s employment if a disability results in Mr. Pettit being unable to work for more than 90 days; provided, however, this will not apply to injury occurring while performing job duties.

 

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Salary and Cash Bonus in Proportion to Total Compensation

The following table sets forth the percentage of each named officer’s total compensation that we paid in the form of base salary and cash bonus for the year 2007.

 

     Percentage
of Total
Compensation
 

J. Russell Porter

   46 %

Michael A. Gerlich

   46 %

Jeffery C. Pettit

   87 %

Outstanding Equity Awards at Fiscal Year-End Table

 

Name

   Number of
Securities
Underlying
Unexercised
Options
Exercisable
   Number of
Securities
Underlying
Unexercised
Options
Unexercisable
   Option
Exercise
Price
   Option
Expiration
Date
   Number of
Shares of
Restricted
Stock That
Have
Not Vested
   Market Value
of Shares of
Restricted
Stock That
Have Not
Vested (1)

J. Russell Porter (2)

   750,000    250,000    $ 3.48    08/04/09    —        —  
   37,500    112,500    $ 4.89    04/05/16    —        —  
   500,000    500,000    $ 2.32    07/14/16    —        —  
   —      —        —      —      225,000    $ 281,250

Michael A. Gerlich (3)

   125,000    125,000    $ 3.57    06/24/10    —        —  
   62,500    187,500    $ 5.11    01/16/16    —        —  
   25,000    75,000    $ 4.89    04/05/16    —        —  
   100,000    200,000    $ 2.32    07/14/16    —        —  
   —      —        —      —      137,500    $ 171,875

Jeffery C. Pettit (4)

   —      —        —      —      112,500    $ 140,625

 

(1) The closing price of our common share on December 31, 2007 was $1.25.

 

(2) The 250,000 unexercisable stock options granted to Mr. Porter that expire on 08/04/09 (grant date of 08/04/04) vest 100% on 08/04/08. The exercise price was denominated at CDN$3.41. At the exchange rate on 12/31/07, this exercise price equates to $3.48. The 112,500 unexercisable stock options granted to Mr. Porter that expire on 04/05/16 (grant date of 04/05/06) vest 33.3% on 04/05/08, 04/05/09 and 04/05/10. The exercise price was denominated at CDN$4.80. At the exchange rate on 12/31/07, this exercise price equates to $4.89. The 500,000 unexercisable stock options granted to Mr. Porter that expire on 07/14/16 (grant date of 07/14/06) vest 50% on 07/14/08 and 07/14/09. The exercise price was denominated in United States dollars at $2.32. The 225,000 restricted common shares granted to Mr. Porter on 07/03/07 vest 33.3% on 07/03/09, 07/03/10 and 07/03/11.

 

(3) The 125,000 unexercisable stock options granted to Mr. Gerlich that expire on 06/24/10 (grant date of 06/24/05) vest 50% on 06/24/08 and 06/24/09. The exercise price was denominated at CDN$3.50. At the exchange rate on 12/31/07, this exercise price equates to $3.57. The 187,500 unexercisable stock options granted to Mr. Gerlich that expire on 01/16/16 (grant date of 01/16/06) vested 33.3% on 01/16/08, 06/16/09 and 06/16/10. The exercise price was denominated at CDN$5.01. At the exchange rate on 12/31/07, this exercise price equates to $5.11. The 75,000 unexercisable stock options granted to Mr. Gerlich that expire on 04/05/16 (grant date of 04/05/06) vest 33.3% on 04/04/08, 04/04/9 and 04/04/10. The exercise price was denominated at CDN$4.80. At the exchange rate on 12/31/07, this exercise price equates to $4.89. The 200,000 unexercisable stock options granted to Mr. Gerlich that expire on 07/14/16 (grant date of 7/14/06) vest 50% on 07/14/08 and 07/14/09. The exercise price was denominated in United States dollars at $2.32. The 137,500 restricted common shares granted to Mr. Gerlich on 07/03/07 vest 33.3% on 07/03/09, 07/03/10 and 07/03/11.

 

(4) Mr. Pettit joined us as our Chief Operating Officer on August 27, 2007. He was granted 112,500 restricted common shares as a condition of his employment that vest 33.3% on 08/27 2009, 08/27/10 and 08/27/11.

 

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Option Exercises and Stock Vested

During the year ended December 31, 2007, no restricted common shares that were granted to the named executive officers vested, and no stock options were exercised by the named executive officers. The named executive officers have no other outstanding stock awards other than those shown above.

Potential Payments Upon Termination or Change of Control

The table below discloses the amount of compensation and/or other benefits due to the named executive officers in the event of their termination of employment, including, but not limited to, in connection with a change in control. The amounts shown assume that such termination was effective as of December 31, 2007, and thus include amounts earned through such date and are estimates of the amounts which would be paid to the named executive officers upon their respective termination. The actual amounts to be paid out can only be determined at the time the executive is terminated.

 

Named Executive Officer

and Post Termination Benefits

   Termination
for other
than
Reasonable
Cause (1)
   Constructive
Termination
and
Termination
in Connection
with Change
of Control (2)
   Termination
for
Reasonable
Cause (3)
   Death (4)    Disability (4)

J. Russell Porter

              

Salary

   $ 1,350,000    $ 2,025,000    $ —      $ 1,350,000    $ 1,350,000

Accrued vacation

     51,924      51,924      51,924      51,924      51,924

Paid health and medical

     27,265      27,265      —        22,474      27,265

Parachute tax gross-up payment (5)

     —        847,832      —        —        —  

Equity compensation (6)

     —        281,250      —        —        —  
                                  

Total

   $ 1,429,189    $ 3,233,271    $ 51,924    $ 1,424,398    $ 1,429,189
                                  

Michael A. Gerlich

              

Salary

   $ 550,000    $ 928,126    $ —      $ 550,000    $ 550,000

Accrued vacation

     15,865      15,865      15,865      15,865      15,865

Paid health and medical

     27,265      27,265      —        22,474      27,265

Parachute tax gross-up payment (5)

     —        340,861      —        —        —  

Equity compensation (6)

     —        171,875      —        —        —  
                                  

Total

   $ 593,130    $ 1,483,992    $ 15,865    $ 588,339    $ 593,130
                                  

Jeffery C. Pettit

              

Salary

   $ 285,000    $ 712,501    $ —      $ —      $ —  

Accrued vacation

     3,398      3,398      3,398      3,398      3,398

Paid health and medical

     —        27,265      —        —        —  

Parachute tax gross-up payment (5)

     —        —        —        —        —  

Equity compensation (6)

     —        140,625      —        —        —  
                                  

Total

   $ 288,398    $ 883,789    $ 3,398    $ 3,398    $ 3,398
                                  

 

(1)

Per Mr. Porter’s employment agreement, if he is involuntarily terminated for any reason other than for reasonable cause (as defined in his employment agreement) and if proper notice is received, Mr. Porter will be entitled to a severance payment equal to two years (“Severance Pay Period”) of the most recent annual gross salary (as shown on his W-2 inclusive of cash bonuses paid) to be paid over 104 weeks after termination. For 2007, this amount was $675,000. If Mr. Porter timely elects COBRA continuation coverage, he and his family will be entitled to continuation of health insurance at our expense, subject to the limitations imposed by law and our insurance plan (currently 18 months). As of December 31, 2007, the cost for health and medical coverage for Mr. Porter and his family was $1,515 per month. If Mr. Porter dies

 

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during the Severance Pay Period, his family will be entitled to continuation of health insurance at our expense, subject to the limitations imposed by law and our insurance plan, for the remaining portion of the Severance Pay Period. At December 31, 2007, the maximum cost over the 24 month Severance Pay Period would be $22,464 at $936 per month. Mr. Porter currently is entitled to 20 working days of vacation per year. He would receive a lump-sum cash payment of his unused vacation time of up to 10 days that are not used during each year employed. As of December 31, 2007, Mr. Porter had available 19.25 days of available accrued but unused vacation pay. In addition, effective on Mr. Porter’s termination for any reason, the unvested portion of all stock options held by Mr. Porter will immediately vest. If Mr. Porter elects to terminate his employment without proper notice, all unvested stock options would be forfeited. All other terms and conditions of his stock options will remain unchanged, including provision that all stock option will terminate 90 day after termination. As of December 31, 2007, Mr. Porter had 1,287,500 stock options that were vested and 862,500 stock options were not vested. On December 31, 2007, the exercise prices of all of Mr. Porter’s stock options were greater than the market price of our common shares. Upon termination for any reason, all of Mr. Porter’s unvested stock options shall vest and be exercisable for period of 90 days. Additionally, on December 31, 2007, he had 225,000 restricted common shares that had not vested having a value on that date of $281,250.

Per Mr. Gerlich’s employment agreement, if he is involuntarily terminated for any reason other than for reasonable cause (as defined in their employment agreement), he will be entitled to a severance payment equal to two years (“Severance Pay Period”) of the most recent annual gross salary (as shown on his W-2 exclusive of cash bonuses paid) to be paid over 100 weeks after termination. If Mr. Gerlich timely elects COBRA continuation coverage, he and his family will be entitled to continuation of health insurance at our expense, subject to the limitations imposed by law and our insurance plan (currently 18 months). As of December 31, 2007, the cost for health and medical coverage for Mr. Gerlich and his family was $1,515 per month. If Mr. Gerlich dies during the Severance Pay Period, his family will be entitled to continuation of health insurance at our expense, subject to the limitations imposed by law and our insurance plan, for the remaining portion of the Severance Pay Period. At December 31, 2007, the maximum cost over the 24 month Severance pay Period would be $22,464 at $936 per month. In addition, Mr. Gerlich will receive a lump-sum cash payment of his unused vacation time of up to 10 days per each year employed up to a maximum of 15 days. As of December 31, 2007, Mr. Gerlich had 14.25 days of available accrued but unused vacation pay. Per Mr. Gerlich’s stock option agreements, he will have 90 days after termination to exercise all vested options. As of December 31, 2007, Mr. Gerlich had 312,500 stock options that were vested and 587,500 stock options that were not vested. The exercise prices of all of Mr. Gerlich’s stock options were greater than the market price of our common shares on December 31, 2007. Additionally, on December 31, 2007, he had 137,500 restricted common shares that had not vested having a value on that date of $171,875.

Per Mr. Pettit’s employment agreement, if he is involuntarily terminated for any reason other than for reasonable cause (as defined in their employment agreement), he will be entitled to a severance payment equal to one year of the most recent annual gross salary (as shown on his W-2 exclusive of cash bonuses paid) to be paid over 52 weeks after termination. In addition, Mr. Pettit will receive, unless termination is for cause, a lump-sum cash payment of his unused vacation time. As of December 31, 2007, Mr. Pettit had 3.1 days of available accrued but unused vacation pay. Additionally, as of December 31, 2007, Mr. Pettit has no stock option grants but had 112,500 restricted common shares that had not vested having a value on that date of $140,625.

 

(2)

Our Employee Change of Control Severance Plan provides that if there is a change of control, covered employees, including named executive officers, will receive a lump sum cash payment equal to the applicable severance period times the sum of the covered employees annual pay and target bonus. Mr. Porter’s severance period is 3, and his annual salary and 50% target bonus at December 31, 2007 was $450,000 and $225,000, respectively. Mr. Gerlich’s severance period is 2.5, and his annual salary and 35% target bonus at December 31, 2007 was $275,000 and $96,250, respectively. Mr. Pettit’s severance period is 2, and his annual salary and 25% target bonus at December 31, 2007 was $285,000 and $71,250,

 

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respectively. The Employee Severance Change of Control Plan provides that if there is a change of control, covered employees, including named executive officers, will be receive reimbursement of COBRA costs. Other termination or severance compensation is determined by the individual named executive officer’s employment agreement.

 

(3) Per their respective employment agreements, we are not obligated to pay any amounts to Messrs. Gerlich or Mr. Porter, other than accrued and unused vacation days and their pro-rata base salary through the date of his termination of employment, as a result of a termination for reasonable cause (as defined in their respective employment agreements). The Company has no obligation to pay Mr. Pettit any amounts if termination is for reasonable cause.

 

(4) Per their respective employment agreements, if Mr. Porter’s or Mr. Gerlich’s employment terminates due to death, his eligible beneficiary will be entitled to receive his severance payment over the severance period described in footnote 1 above. If Messrs. Porter’s or Gerlich’s employment terminates due to a disability (as defined in their respective employment agreements), he shall be entitled to receive a severance payment in the form and amount as determined in footnote 1 above. The Company has no obligation to pay Mr. Pettit any amount; except for accrued and unused vacation pay.

 

(5) The Company’s Employee Change of Control Severance Plan provides that if the named executive officer receives a payment or benefit that is subject to the “golden parachute” excise tax, the named executive officer will receive an additional payment under the severance plan to make him or her “whole” for that excise tax and any taxes on the additional parachute tax gross-up payment (the “gross-up payment”). To determine Mr. Porter’s amount of the gross-up payment, Mr. Porter’s “base amount” was calculated using the five-year average of his compensation for the years 2002-2006. In the case of Mr. Gerlich, the amount is calculated using the two-year average of his W-2 earnings for 2006 and his annualized salary plus paid bonus for 2005, as his employment with the Company commenced in mid-2005. The payments received in connection with the change of control in excess of a named executive officer’s “base amount” is considered an “excess parachute payment” as provided by Section 280G of the Code. If the total of all “parachute payments” is equal to or greater than three times the base amount, the amount of the excess parachute payment will be subject to the excise tax. In making the calculation, the following assumptions were used: (a) the change of control occurred on December 31, 2007, (b) the closing price of our stock was $1.25 on such date, (c) the excise tax rate under Section 4999 of the Code is 20%, the federal income tax rate is 35%, the Medicare rate is 1.45%, the adjustment to reflect the phase-out of itemized deductions is 1.05%, and there is no state or local income taxes, (d) no amounts will be discounted as attributable to reasonable compensation, (e) all cash severance payments are contingent upon a change of control, (f) the presumption required under applicable regulations that the equity awards granted were contingent upon a change of control could be rebutted.

 

(6) The Gastar Employee Change of Control Severance Plan provides that if there is a transaction that results in a change of control and the surviving entity does not assume or convert the awards, then such awards will immediately vest. For the purpose of this disclosure, we have assumed the surviving entity does not assume or convert the awards. The amount shown is the product of the number of restricted shares held by the named executive officer times the closing price of our common shares on December 31, 2007, or $1.25 per common share.

The employment agreements of Messrs. Porter, Gerlich and Pettit generally use the following terms:

“Reasonable Cause” means any of the following (a) an act or omission that amounts to dishonesty, disloyalty, fraud, deceit, gross negligence, willful misconduct or recklessness, including the willful violation of any of our policies or procedures; (b) a felony conviction; (c) a breach of any material term of the employment agreement; (d) the refusal to perform any services that the named executive officer is required to perform under the employment agreement; or (e) with respect to Mr. Porter’s agreement only, an act that is determined by the vote of two-thirds of the shareholders to constitute “Reasonable Cause” or to be detrimental to the best interests of the Company.

 

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“Disability” means the inability to perform the functions essential to the named executive officer’s position with or without accommodation during a continuous 12 month period, due to physical or mental illness of the named executive officer. The date of disability is the last day of the 12 month period. Successive periods of illness or injury that are due to the same or related causes are considered one period of disability unless the named executive officer returns to work full-time for three successive months. Except that Mr. Pettit’s employment agreement defines “disability” as the inability to perform all duties of his job for more than ninety days.

Mr. Gerlich’s employment agreement describes a “change of control” as a “change of control” as a result of a sale of all or substantially all of our assets, purchase of over 50% of our stock, or through merger, consolidation, corporate restructuring or otherwise.

The Employee Change of Control Severance Plan generally uses the following terms:

A “change of control” means (1) the consummation of a merger, consolidation, reorganization or other transaction whereby our shareholders retain less than 50% control, directly or indirectly, of us or the surviving company, (2) our incumbent directors cease to constitute a majority of the board of directors or (3) a sale or other disposition of all or substantially all of our assets.

“Involuntary Termination” means any termination of employment that occurs within two years following a Change of Control and which (1) does not result from a voluntary resignation by the covered employee (except for Good Reason), (2) results from a resignation by the Covered Employee for Good Reason, but (3) does not result from a termination by the Company for Cause, as a result of the covered employee’s death or Disability, or because the covered employee declined to accept an offer of comparable employment from the successor employer.

“Good Reason” means the occurrence of any of the following after a Change of Control: (1) relocating the covered employee’s place of employment without his consent to a place outside of the 35-mile radius of his previous place of employment, (2) reducing the covered employee’s annual base salary or materially reducing his benefits that were provided immediately prior to the Change of Control, (3) the Company’s material breach of the Employee Change of Control Severance Plan, (4) a purported termination of the covered employee’s employment for Cause by the Company that does not otherwise comply with the terms of the Employee Change of Control Severance Plan, or (5) a substantial reduction in the covered employee’s position or responsibilities. In certain circumstances, the occurrence of one of these events within six months prior to the Change of Control may be “Good Reason.”

Our Employee Change of Control Severance Plan provides that if any payment made, or benefit provided, to or on behalf of a covered employee pursuant to the plan or otherwise (“Payments”) results in a covered employee being subject to the excise tax imposed by Section 409 of the Code (or any successor or similar provision) (“Excise Tax”), we shall, as soon as administratively practicable, pay such covered employee an additional amount in cash (the “Additional Payment”) such that after payment by the covered employee of all taxes, including, without limitation, any taxes imposed on the Additional Payment, such Covered Employee retains an amount of the Additional Payment equal to the Excise Tax imposed on the Payments. Such determinations shall be made by our independent certified public accountants.

Mr. Porter’s employment agreement contains a confidentiality provision applicable both during the term of his employment and following his termination of employment. Pursuant to the confidentiality provision, Mr. Porter agrees to hold in confidence and not disclose any confidential information about our business, except as required in the ordinary course of performing his employment duties with us. A breach of this confidentiality provision could result in a reasonable cause termination. Mr. Porter’s employment agreement further provides that, for a period of two years after his termination of employment with us for a reason other than reasonable cause, (six months if terminated for reasonable cause), Mr. Porter shall not, directly or indirectly, compete with us.

 

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Mr. Gerlich’s employment agreement provides that, unless specifically pre-approved by the Chief Executive Officer in writing, which approval may not be unreasonably withheld, Mr. Gerlich will not directly compete (as defined in the employment agreement) with us for a period of two years following his termination of employment.

Mr. Pettit’s employment agreement contains a confidentiality provision applicable both during the term of his employment and following his termination of employment. Pursuant to the confidentiality provision, he agrees to hold in confidence and not disclose any confidential and proprietary information about our business, except as required in the ordinary course of performing his employment duties with us. A breach of this confidentiality provision could result in a reasonable cause termination.

Compensation of Directors

Since November 2005, directors who are not employees receive the following fees:

 

   

$7,500 for all meetings attended in person;

 

   

$1,500 per meeting attended telephonically; and

 

   

$500 per committee meeting attended in person.

Directors who are not employees are eligible to receive stock option grants under our stock option plans. During the fiscal year ended December 31, 2007, stock options were issued to the Messrs. Badwi, Crow, Penner and Selser to purchase 150,000, 100,000, 200,000 and 100,000 common shares, respectively. Each stock option vests over a four-year period (25% on the first anniversary of the grant and 25% on each of the second, third and fourth anniversaries of the grant) and expires 10 years from the date of grant. The stock options granted to Messrs. Badwi and Crow have an exercise price of $2.20 per common share. Mr. Penner’s stock option has an exercise price of $2.19. Mr. Selser’s 2007 stock options consist of two grants, one for 200,000 common shares and another for 100,000 common shares, having exercise prices of $2.17 and $2.20 per share, respectively.

The following table shows certain information about directors’ compensation for the year ended December 31, 2007:

Director Compensation Table

 

     Fees Earned
or Paid
in Cash
   Option
Awards (1)
   Total

Abby F. Badwi

   $ 45,000    $ 327,439    $ 372,439

Thomas L. Crow (2)

   $ 24,000    $ 190,790    $ 214,790

Richard A. Kapuscinski (3)

   $ 9,500    $ 161,572    $ 171,072

Robert D. Penner (4)

   $ 36,000    $ 58,629    $ 94,629

John M. Selser Sr. (5)

   $ 34,000    $ 114,323    $ 148,323

 

(1)

We have granted to our directors stock options in addition to their specified compensation to be paid as directors. These grants are, in part, to compensate our directors for the stricter regulatory role in which they have to operate and to provide them with incentives to remain as a director by offering them a long-term stake in our potential future value. The fair values of stock option awards were determined in accordance with SFAS 123R by using the Black-Scholes-Merton valuation model as of the date of grant. See Note 8—Equity Compensation Plans—Determining Fair Value under SFAS 123R to our consolidated financial statements , which begins on Page F-1, for a discussion of assumptions made in the valuation of option awards. The amounts shown in this column represents the stock-based compensation expense, prior to a 5.0% deduction for estimated forfeitures, attributable to stock options grants that is recognized by us for the year ended December 31, 2007 that was attributable to all stock options granted to the Directors and

 

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outstanding during the year. During 2007, Messrs. Badwi, Crow, Penner and Selser were awarded stock options to purchase 150,000, 100,000, 200,000 and 100,000 common shares, respectively. As of December 31, 2007, Messrs. Badwi, Crow, Penner and Selser held stock options to purchase an aggregate of 950,000, 500,000, 200,000 and 300,000 common shares. Total fair value attributable to stock options granted to Messrs. Badwi, Crow, Penner and Selser during 2007 as of the date of grant was $168,975, $112,650, $225,700 and $112,650, respectively. Mr. Kapuscinski resigned as a director of the Board effective June 19, 2007 and received no stock based compensation grants in 2007. In determining the number of stock options granted to directors, consideration was given to the number of stock options previously granted to the directors. Additional consideration was given to Mr. Badwi, who served as the chairman of the Audit Committee, as well as other committees of the Board of Directors. Additional consideration also was given to Mr. Penner, who replaced Mr. Badwi as Chairman of the Audit Committee.

 

(2) Mr. Crow resigned as a director of the Board of Directors effective January 1, 2008.

 

(3) Mr. Kapuscinski resigned as a director of the Board effective June 19, 2007.

 

(4) Mr. Penner became a director of the Board effective July 16, 2007.

 

(5) Mr. Selser became a director of the Board effective April 4, 2007.

Compensation Committee Interlocks and Insider Participation

During the year ended December 31, 2007, the compensation committee of our Board of Directors, which we refer to as the Remuneration Committee, was comprised of Messrs. Badwi (Chairman), Crow, Kapuscinski and Selser, who replaced Mr. Kapuscinski upon his resignation as a director of the Board of Directors on June 19, 2007. Mr. Crow resigned from the Board of Directors effective January 1, 2008. Currently, our Remuneration Committee is comprised of Messrs. Badwi, Penner and Selser. None of our named executive officers serves as a member of the board of directors or compensation committee (or committee performing similar functions) of any other entity, one or more of whose executive officers serve on our Board of Directors or Remuneration Committee.

 

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

Securities Authorized for Issuance under Equity Compensation Plans

2002 Stock Option Plan

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. In April 2004, our Board of Directors amended the provisions of the 2002 Stock Option Plan to specifically incorporate a provision to provide for stock options to be exercised on a cashless basis, whereby we issue the optionee the number of common shares equal to the stock option exercised less the number of common shares which when multiplied by the market price at the date of exercise equals the aggregate exercise price for all of the common shares exercised.

We have authorization to issue, and have reserved, a maximum of 25.0 million common shares for awards under the 2002 Stock Option Plan. If any stock option granted under the 2002 Stock Option Plan expires or terminates for any reason in accordance with its terms without being exercised, the unpurchased shares subject to that stock option will become available for other option grants under the 2002 Stock Option Plan.

The 2002 Stock Option Plan is administered by our Remuneration Committee. Pursuant to the 2002 Stock Option Plan, our Remuneration Committee may allocate non-transferable options to purchase common shares to

 

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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 and the aggregate number of common shares underlying the options granted to each individual 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 Remuneration Committee, but that exercise price cannot be less than the price permitted by any stock exchange on which our common shares are then listed.

As of December 31, 2007, we had stock options outstanding to purchase 10,173,750 common shares pursuant to the 2002 Stock Option Plan, 5,127,916 common shares of which are vested but have not been exercised.

2006 Gastar Long-Term Stock Incentive Plan

On June 1, 2006, at the annual meeting of shareholders, the shareholders approved the 2006 Gastar Long-Term Stock Incentive Plan. The 2006 Gastar Long-Term Stock Incentive Plan authorizes the issuance of stock options, restricted common shares and stock appreciation rights to directors, officers and employees of the Company and its subsidiaries to purchase a maximum of 5.0 million common shares. Stock options may be exercised on a cash or cashless basis. The contractual life and vesting period for grants will be determined at the time stock options are granted. If any stock option granted under the 2006 Gastar Long-Term Stock Incentive Plan expires or terminates for any reason in accordance with the its terms without being exercised, the unpurchased shares subject to that stock option will become available for other option grants under the 2006 Gastar Long-Term Stock Incentive Plan. If any restricted common shares granted under the 2006 Gastar Long-Term Stock Incentive Plan that are unvested at the time of a grantee’s termination of employment, the unvested shares will be canceled with a corresponding reduction of common shares outstanding.

The 2006 Gastar Long-Term Stock Incentive Plan is administered by our Remuneration Committee. Pursuant to the 2006 Gastar Long-Term Stock Incentive Plan, our Remuneration Committee may allocate non-transferable options to purchase common shares to directors, officers and employees of Gastar and its subsidiaries. At the time of granting stock options under the 2006 Gastar Long-Term Stock Incentive Plan, the aggregate number of common shares underlying all stock options granted and the aggregate number of common shares underlying the options granted to each individual 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. Stock options issued pursuant to the 2006 Gastar Long-Term Stock Incentive Plan have an exercise price determined by the Remuneration Committee, but that exercise price cannot be less than the price permitted by any stock exchange on which our common shares are then listed.

As of December 31, 2007, a total of 1,096,00 restricted common shares had been granted to employees and were outstanding under the 2006 Gastar Long-Term Stock Incentive Plan. As of December 31, 2007, there were no stock options outstanding under the 2006 Gastar Long-Term Stock Incentive plan.

 

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Common Stock that may be Issued upon the Exercise of Stock Options

The following table provides information as of December 31, 2007 about our common stock that may be issued upon the exercise of stock options under (i) all compensation plans previously approved by security holders and (ii) individual compensation arrangements not approved by security holders.

Equity Compensation Plan Information

 

Plan Category

   Number of
Securities to be
Issued Exercise,
Exercise of
Outstanding
Options, Warrants
and Rights Vesting of
Restricted Vesting of
Restricted Common
Share Grants
   Weighted Average
Exercise Price
of Outstanding
Options, Warrants
and Rights
Vesting of
Restricted Common
Share Grants (1)
   Number of
Securities
Remaining
Available for
Future
Issuance
under Equity
Compensation
Plans

Equity compensation plans approved by security holders:

        

2002 Stock Option Plan

   10,173,750    $ 2.86    16,083,050

2006 Gastar Long-Term Stock Incentive Plan

   1,096,000       3,904,000
   11,269,750       19,987,050
            

Equity compensation plans not approved by security holders

   —         —  
            

Total

   11,269,750       19,987,050
            

 

(1) During the years 2005 and earlier, we granted stock options with the exercise prices denominated in CDN$. In July 2006, we began granting all stock options with exercise prices denominated in US$. For the purposes of this table, exercise prices that were denominated in CDN$ have been converted to US$ at the exchange rate on December 31, 2007.

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth certain information about the beneficial ownership of common shares by:

 

   

Each of our directors;

 

   

Named executive officers listed in the Summary Compensation Table set forth under the caption “Compensation of Executive Officers and Directors” below;

 

   

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

 

   

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

Unless otherwise indicated and subject to community property laws where applicable, management believes that all persons named in the following table have sole voting and investment power over all common shares reported as beneficially owned by them.

 

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The following table is based upon information supplied by officers, directors, certain named individuals, principal shareholders and from documents filed with the SEC. Applicable percentages are based on 208,204,570 common shares outstanding on March 10, 2008, subject to adjustment for each beneficial owner as described above. To the knowledge of our directors and executive officers, as of March 10, 2008, no person, firm or corporation own, directly or indirectly, or exercise control or direction over voting securities carrying more than 5% of the voting rights attached to any class of our voting securities, except as indicated in the below.

 

Name and Address of Beneficial Owner (1)

   Amount and
Nature of
Beneficial
Ownership
   Percent
Common
Shares
Outstanding
 

Our greater than 5% shareholders:

     

Chesapeake Energy Corporation (2)

6100 North Western Avenue,

Oklahoma City, OK 73118

   33,908,836    16.3 %

Palo Alto Investors, LLC (2)

470 University Avenue,

Palo Alto, CA 94301

   23,876,100    11.5 %

Ospraie Management, LLC (2).

320 Park Avenue, 27th Floor,

New York, NY 10022

   12,308,100    8.8 %

GeoStar Corporation (3)

2480 W. Campus Drive, Building C,

Mt. Pleasant, MI 48858

   15,767,524    7.6 %

Our Directors, who are not employees: (4)

     

Abby F. Badwi (5)

   441,667    *  

Robert D. Penner

   —      *  

John M. Selser Sr. (6)

   50,000    *  

Our named executive officers: (4)

     

J. Russell Porter, Chairman, President,
Chief Executive Officer and Chief Operating Officer (7)

   3,605,000    1.7 %

Michael A. Gerlich, Vice President and
Chief Financial Officer (8)

   425,000    *  

Jeffery C. Pettit, Vice President,
Chief Operating Officer

   —      *  

Directors and named executive officers, as a group (6 persons)

   4,521,667    2.1 %

 

* Less than 1%.

 

(1) Unless otherwise indicated and subject to community property laws where applicable, management believes that all persons named in the following table have sole voting and investment power over all common shares reported as beneficially owned by them.

 

(2) Consists of common shares owned directly.

 

(3) The number of common shares shown as beneficially owned by GeoStar is based on its most recent Form 13D filing with the SEC dated July 24, 2006. We have reasons to believe that GeoStar beneficially owns significantly less than 5% of our outstanding common shares.

 

(4) The contact address for our directors and named executive officers is 1331 Lamar Street, Suite 1080, Houston, Texas 77010.

 

(5) Consists of 441,667 common shares common shares underlying stock options that currently are vested or will vest or be exercisable within 60 days of March 10, 2008 regardless of price.

 

(6) Consists of 50,000 common shares underlying stock options that currently are vested or will vest or be exercisable within 60 days of March 10, 2008 regardless of price.

 

(7) Consists of 2,280,000 common shares owned directly and 1,325,000 common shares underlying stock options that currently are vested or will vest or be exercisable within 60 days of March 10, 2008 regardless of price.

 

(8) Consists of 25,000 common shares owned directly and 400,000 common shares underlying stock options that currently are vested or will vest or be exercisable within 60 days of March 10, 2008 regardless of price.

 

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Item 13. Certain Relationships, Related Transactions, and Director Independence

Information concerning related party transactions is set forth in Note 13—Related Party Transactions to our consolidated financial statements, which begin on page F-1.

Our written policy or procedure for the review, approval or ratification of related party transactions is set forth in the Terms of Reference for the Audit Committee. The Audit Committee reviews and approves all related party transactions. In the course of its review, the Audit Committee considers the nature of the transactions and the costs to be incurred by us or payments to us; an analysis of the costs and benefits associated with the transaction and a comparison of comparable or alternative goods or services that are available to us from unrelated parties; the business advantage we would gain by engaging in the transaction; and an analysis of the significance of the transaction to us and to the related party. As a matter of course, any Audit Committee member that cannot be viewed as independent will withhold his vote, declaring his interest in the transaction. A vote of a majority of the remaining members is required to approve a related party transaction.

Our Board of Directors is comprised of four members whose names and committee memberships are set forth below. Our Board of Directors has determined that a majority of the members of the Board of Directors have no material relationship with the Company (either directly or as partners, shareholders or officers of an organization that has a relationship with the Company) and are independent within the meaning of the American Stock Exchange director independence standards. J. Russell Porter, as our President and Chief Executive Officer, is not considered to be independent. The Board has determined that each of the members of the Audit Committee, the Remuneration Committee, the Nomination Committee, Governance Committee and the Reserve Committee has no material relationship to the Company (either directly or as a partner, shareholder or officer of an organization that has a relationship with the Company) and is independent within the meaning of the American Stock Exchange director independence standards.

 

Name and Position

   Independence    Committee
Membership
 

J. Russell Porter, Chairman, Chairman, President and CEO

   No    —    

Abby F. Badwi, Director

   Yes    Governance *
      Audit  
      Reserve  
      Remuneration  *
      Nomination *

Robert D. Penner, Director

   Yes    Governance  
      Audit *
      Reserve  
      Remuneration  
      Nomination  

John M. Selser Sr., Director

   Yes    Governance  
      Audit  
      Reserve *
      Remuneration  
      Nomination  

Thomas E. Robinson, former Director (1)

   No   

Matthew J.P. Heysel, former Director (2)

   Yes   

Richard A. Kapuscinski, former Director (3)

   Yes   

Thomas L. Crow, Director, former Director (4)

   Yes   

 

* Indicates chairmanship of committee.

 

(1) Mr. Robinson resigned as our Chairman of the Board effective August 1, 2006. Mr. Robinson is the president of Geostar Corporation, a related party. During his time as Chairman and a member of our Board of Directors, Mr. Robinson was not a member of any of the committees of the Board of Directors.

 

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(2) Mr. Heysel did not stand for reelection at the Annual Meeting of Shareholders held June 1, 2006. While a member of our Board of Directors, Mr. Heysel was member of the Audit Committee, Governance Committee and Remuneration Committee.

 

(3) Mr. Kapuscinski resigned as a director of the Board of Directors effective June 19, 2007. While a member of our Board of Directors, Mr. Kapuscinski was member of the Remuneration Committee, Governance Committee and Reserve Committee.

 

(4) Mr. Crow resigned as a director of the Board of Directors effective January 1, 2008. While a member of our Board of Directors, Mr. Crow was member of the Governance Committee, Audit Committee, Reserve Committee, Remuneration Committee and Nomination Committee.

 

Item 14. Principal Accountant Fees and Services

BDO Seidman, LLP was appointed our independent registered public accounting firm on January 10, 2006 to replace its Canadian affiliate, BDO Dunwoody LLP, independent registered public accounting firm, as a result of the relocation of our corporate headquarters to Houston, Texas and the adoption of US GAAP for our financial reporting. Aggregate fees billed for professional services rendered to us by BDO Seidman, LLP and BDO Dunwoody LLP, for the years ended December 31, 2007 and 2006 were:

 

     For the Year Ended
December 31,
         2007            2006    
     (in thousands)

Audit fees:

     

BDO Seidman, LLP

   $ 542    $ 243

BDO Dunwoody LLP

     46      27
             
     588      270

Audit related fees:

     

BDO Seidman, LLP

     —        —  

BDO Dunwoody LLP

     —        —  
             
     —     

Tax fees:

     

BDO Seidman, LLP

     —        —  

BDO Dunwoody LLP

     31      18
             
     31      18

Total:

     

BDO Seidman, LLP

     542      243

BDO Dunwoody LLP

     77      45
             

Total

   $ 619    $ 288
             

The audit fees for the years ended December 31, 2007 and 2006 were primarily for professional services rendered in connection with the audit of our consolidated financial statements, fees related to our compliance with the Sarbanes-Oxley Act of 2002, together with services rendered in connection with quarterly reviews of financial statements and various documents filed with various governmental agencies. Audit related fees primarily include the review of certain documents filed with the SEC, the 12  3 / 4 % Senior Secured Notes financing and related offering circular, and other accounting related matters. Fees for tax services were for services related to tax compliance, including the preparation of tax returns. During 2007 and 2006, there were no other accounting fees.

The Audit Committee pre-approves all audit and non-audit services provided by our independent registered public accounting firm prior to its engagement with respect to such services. In addition to separately approved services, the Audit Committee’s pre-approval policy provides for pre-approval of all audit and non-audit services provided by our independent registered public accounting firm.

 

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PART IV

 

Item 15. Exhibits, Financial Statement Schedules

(a)-1 Financial Statements and Schedules:

The financial statements are set forth beginning on Page F-1 of this Form 10-K. Financial statement schedules have been omitted since they are either not required, not applicable, or the information is otherwise included.

(a)-2 Schedule II—Valuation and Qualifying Accounts

Schedule II—Valuation and Qualifying Accounts appears at the end of the notes, which begin on Page F-1 of this Form 10-K.

(b) Exhibits:

The following is a list of exhibits filed as part of this Form 10-K. Where so indicated, exhibits, which were previously filed, are incorporated herein by reference.

EXHIBIT INDEX

 

Exhibit
Number

  

Description

3.1

   Amended and Restated Articles of Incorporation of Gastar Exploration Ltd. (incorporated herein by reference to Appendix B to the Company’s Proxy Statement for the Annual and Special Meeting of Shareholders dated April 30, 2007 to be held June 1, 2007.

3(ii)

   Bylaws of Gastar Exploration Ltd. approved at March 31, 2000 and amended August 21, 2006 (incorporated herein by reference to Exhibit 3(ii) of the Company’s Current Report on Form 8-K dated December 19, 2006. File No. 001-37214).

4.1

   Indenture dated November 12, 2004 between Gastar Exploration Ltd. and CIBC Mellon Trust Company as trustee (incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-1, filed on August 12, 2005. Registration No. 333-127498).

4.2

   Form of 9.75% Convertible Senior Unsecured Subordinated Debenture of Gastar Exploration Ltd. (incorporated by reference to Exhibit 4.2 of the Company’s Registration Statement on Form S-1, filed on August 12, 2005. Registration No. 333-127498).

4.3

   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 Debenture of Gastar Exploration Ltd. (incorporated by reference to Exhibit 4.4 of the Company’s Registration Statement on Form S-1, filed on August 12, 2005. Registration No. 333-127498).

4.4

   Form of Subscription Agreement for U.S. purchasers of 9.75% Convertible Senior Unsecured Subordinated Debenture of Gastar Exploration Ltd (incorporated by reference to Exhibit 4.5 of the Company’s Registration Statement on Form S-1, filed on August 12, 2005. Registration No.
333-127498).

4.5

   Form of Subscription Agreement for foreign purchasers of 9.75% Convertible Senior Unsecured Subordinated Debenture of Gastar Exploration Ltd. (incorporated by reference to Exhibit 4.6 of the Company’s Registration Statement on Form S-1, filed on August 12, 2005. Registration No.
333-127498).

4.6

   Registration Rights Agreement dated as of June 17, 2005, by and among Gastar Exploration Ltd. and the purchasers named therein (incorporated by reference to Exhibit 4.9 of the Company’s Registration Statement on Form S-1, filed on August 12, 2005. Registration No. 333-127498).

 

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Exhibit
Number

  

Description

4.7  

   Form of Subscription Agreement for U.S. purchasers of common shares of Gastar Exploration Ltd. in a private placement dated June 30, 2005 (incorporated by reference to Exhibit 4.10 of the Company’s Registration Statement on Form S-1, filed on August 12, 2005. Registration No. 333-127498).

4.8  

   Form of Subscription Agreement for foreign purchasers of common shares of Gastar Exploration Ltd. in a private placement dated June 30, 2005 (incorporated by reference to Exhibit 4.11 of the Company’s Registration Statement on Form S-1, filed on August 12, 2005. Registration No.
333-127498).

4.9  

   Form of 10% subordinated note issued June 2004 (incorporated by reference to Exhibit 4.14 of the Company’s Amendment No. 4 to Registration Statement on Form S-1/A, filed on December 22, 2005. Registration No. 333-127498).

4.10

   Form of warrant to purchase common shares of Gastar Exploration Ltd issued in connection with the sale of 10% subordinated notes in June 2004 (incorporated by reference to Exhibit 4.15 of the Company’s Registration Statement on Form S-1, filed on August 12, 2005. Registration No.
333-127498).

4.11

   Agreement between Gastar Exploration Ltd. and GeoStar Corporation dated August 11, 2005 (incorporated by reference to Exhibit 4.17 of the Company’s Amendment No. 1 to Registration Statement on Form S-1/A, filed on October 30, 2005. Registration No. 333-127498).

4.12

   Common Share Purchase Agreement between Gastar Exploration Ltd. and Chesapeake Energy Corporation dated November 4, 2005 (incorporated by reference to Exhibit 4.19 of the Company’s Amendment No. 2 to Registration Statement on Form S-1/A, filed on November 22, 2005. Registration No. 333-127498).

4.13

   Registration Rights Agreement between Gastar Exploration Ltd. and Chesapeake Energy Corporation dated November 4, 2005 (incorporated by reference to Exhibit 4.20 of the Company’s Amendment No. 2 to Registration Statement on Form S-1/A, filed on November 22, 2005. Registration No.
333-127498).

4.14

   Facsimile of common share certificate of Gastar Exploration Ltd. (incorporated by reference to Exhibit 4.21 of the Company’s Amendment No. 3 to Registration Statement on Form S-1/A, dated December 15, 2005. Registration No. 333-127498).

4.15

   Form of Subscription Agreement for private offering of 25.0 million common shares (incorporated by reference to the Company’s Current Report on Form 8-K dated November 15, 2006.)

4.16

   Indenture related to the 12  3 / 4 % Senior Secured Notes due November 29, 2012, dated as of November 29, 2007, between Gastar Exploration USA, Inc., Gastar Exploration Ltd., Wells Fargo Bank, National Association, as Trustee and Collateral Agent and each of the other Guarantors party thereto (including the form of 12  3 / 4 % Senior Secured Note due 2012) 2007 (incorporated by reference to the Company’s Current Report on Form 8-K dated December 4, 2007).

4.17

   Registration Rights Agreement, dated as of November 29, 2007, among Gastar Exploration USA, Inc., Gastar Exploration Ltd., each of the other Guarantors party thereto, Jefferies & Company, Inc., Johnson Rice & Company L.L.C. and Pritchard Capital Partners, LLC 2007 (incorporated by reference to the Company’s Current Report on Form 8-K dated December 4, 2007).

4.18

   Intercreditor Agreement dated November 29, 2007 among Gastar Exploration USA, Inc., Gastar Exploration Ltd., each of the Guarantors party thereto, Amegy Bank National Association, as First Priority Agent, and Wells Fargo National Association, as Second Priority Agent 2007 (incorporated by reference to the Company’s Current Report on Form 8-K dated November 13, 2007).

 

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Exhibit
Number

  

Description

  4.19  

   Credit Agreement, dated November 29, 2007, among Gastar Exploration USA, Inc., the Guarantors party thereto and Amegy Bank National Association as Administrative Agent and Letter of Credit Issuer 2007 (incorporated by reference to the Company’s Current Report on Form 8-K dated December 4, 2007).

10.1*  

   The Gastar Exploration Ltd. 2002 Stock Option Plan, dated July 5, 2002 as periodically amended (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated December 4, 2006. File No. 001-32714).

10.2*  

   Employment Agreement dated March 23, 2005 by and among First Sourcenergy Wyoming, Inc., Gastar Exploration Ltd. and J. Russell Porter (incorporated by reference to Exhibit 10.2 of the Company’s Registration Statement on Form S-1, filed on August 12, 2005. Registration No.
333-127498).

10.3*  

   Employment Agreement dated April 26, 2005 by and among First Sourcenergy Wyoming, Inc., Gastar Exploration Ltd. and Michael A Gerlich (incorporated by reference to Exhibit 10.3 of the Company’s Registration Statement on Form S-1, filed on August 12, 2005. Registration No.
333-127498).

10.4    

   Purchase and Sale Agreement between GeoStar Corporation and Gastar Exploration Ltd. covering Wyoming and Montana producing properties dated June 16, 2005 (incorporated by reference to Exhibit 10.4 of the Company’s Amendment No. 1 to Registration Statement on Form S-1/A, filed on October 30, 2005. Registration No. 333-127498).

10.5    

   Purchase and Sale Agreement between GeoStar Corporation and Gastar Exploration Ltd. covering Wyoming and Montana non-producing properties dated June 16, 2005 (incorporated by reference to Exhibit 10.5 of the Company’s Amendment No. 1 to Registration Statement on Form S-1/A, filed on October 30, 2005. Registration No. 333-127498).

10.6    

   Purchase and Sale Agreement between GeoStar Corporation and Gastar Exploration Ltd. covering Texas producing properties dated June 16, 2005 (incorporated by reference to Exhibit 10.6 of the Company’s Amendment No. 1 to Registration Statement on Form S-1/A, filed on October 30, 2005. Registration No. 333-127498).

10.7    

   Purchase and Sale Agreement between GeoStar Corporation and Gastar Exploration Ltd. covering Texas non-producing properties dated June 16, 2005 (incorporated by reference to Exhibit 10.7 of the Company’s Amendment No. 1 to Registration Statement on Form S-1/A, filed on October 30, 2005. Registration No. 333-127498).

10.8    

   Participation and Operating Agreement between GeoStar Corporation and Gastar Exploration Ltd. dated June 15, 2001 (incorporated by reference to Exhibit 4.19 of the Company’s Amendment No. 2 to Registration Statement on Form S-1/A, filed on November 22, 2005. Registration No.
333-127498).

10.9    

   Promissory Note for $15 million between GeoStar Corporation and Gastar Exploration Ltd. dated August 11, 2001 (incorporated by reference to Exhibit 10.9 of the Company’s Amendment No. 1 to Registration Statement on Form S-1/A, filed on October 30, 2005. Registration No. 333-127498).

10.10*

   Form of Gastar officer stock option grant (incorporated herein by reference to Exhibit 10.10 of the Company’s annual Report on form 10-K for the fiscal year ended December 31, 2005. File No.
001-32714).

10.11*

   Gastar Exploration Ltd. 2006 Long-Term Stock Incentive Plan (incorporated herein by reference to Exhibit 10.11 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006. File No. 001-32714).

 

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Index to Financial Statements

Exhibit
Number

  

Description

10.12*

   Form of Indemnity Agreement for Directors and Certain Executive Officers (incorporated herein by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated December 19, 2006. File No. 001-32714).

10.13*

   Form of Gastar Exploration Ltd. Employee Change of Control Severance Plan effective as of March 23, 2007 (incorporated by reference to Exhibit 10.13 of the Company’s Annual Report on Form
10-K for the fiscal year ended December 31, 2006. File No. 001-32714).

10.14

   Common Share Purchase Agreement between Gastar Exploration Ltd. and Navasota Resources, L.P. dated as of May 9, 2007, in connection with the issuance and sale of 10,000,000 common shares (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated May 15, 2007. File No. 001-32714).

10.15

   Registration Rights Agreement by and between Gastar Exploration Ltd. and Navasota Resources, L.P. dated as of May 9, 2007 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated May 15, 2007. File No. 001-32714).

10.16

   Ratification and Assumption of LOI between and among Gastar Exploration Ltd., Gastar Exploration Texas LP and Navasota Resources, L.P. dated May 9, 2007, with Letter of Intent dated April 27, 2007 between and among Gastar Exploration Ltd., Gastar Exploration Texas LP, Chesapeake Energy Corporation and Chesapeake Exploration Limited Partnership, attached thereto as Exhibit A (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated May 15, 2007. File No. 001-32714).

10.17*

   Letter Agreement dated July 5, 2007, which sets forth the terms of the appointment of Jeffrey C. Pettit as Vice President and Chief Operating Officer of Gastar Exploration Ltd. (incorporated herein by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated August 21, 2007. File No. 001-32714).

10.18*†

   Form of Gastar Exploration Ltd. Employee Change of Control Severance Plan effective as of March 23, 2007 and as amended and restated effective February 15, 2008.

14.1

   Gastar Exploration Ltd. Code of Ethics, adopted effective December 15, 2005 (incorporated herein by reference to Exhibit 14.1 of the Company’s Amendment No 4 to Registration Statement on Form S-1/A, dated December 22, 2005, Registration No. 333-27498).

21.1†

   Subsidiaries of Gastar Exploration Ltd.

23.1†

   Consent of BDO Seidman, LLP.

23.2†

   Consent of Netherland Sewell & Associates, Inc.

31.1†

   Certification of chief executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2†

   Certification of chief financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1††

   Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2††

   Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

* Management contract or compensatory plan or arrangement.

 

Filed herewith.

 

†† Furnished herewith.

 

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Index to Financial Statements

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

GASTAR EXPLORATION LTD.
/s/    J. R USSELL P ORTER        

J. Russell Porter,

Chairman, President,

Chief Executive Officer and Chief Operating
Officer (principal executive officer)

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

Name

  

Title

 

Date

/s/    J. R USSELL P ORTER        

J. Russell Porter

   Chairman, President, Chief Executive Officer, and Chief Operating Officer (principal executive officer)   March 17, 2008

/s/    M ICHAEL A. G ERLICH        

Michael A. Gerlich

   Vice President and Chief Financial Officer (principal accounting officer)   March 17, 2008

/s/    A BBY F. B ADWI        

Abby Badwi

   Director   March 17, 2008

/s/    R OBERT D. P ENNER        

Robert D. Penner

   Director   March 17, 2008

/s/    J OHN M. S ELSER S R .        

John M. Selser Sr.

   Director   March 17, 2008

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

     Page

Report of Independent Registered Public Accounting Firm

   F-2

Consolidated Balance Sheets as of December 31, 2007 and 2006

   F-3

Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005

   F-4

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2007, 2006 and 2005

   F-5

Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005

   F-6

Notes to Consolidated Financial Statements

   F-7

 

F-1


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Index to Financial Statements

Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

Gastar Exploration Ltd.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Gastar Exploration Ltd. (the “Company”) and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2007. In connection with our audit of the financial statements, we have also audited the schedule listed in Item 15(a)(2) of this Form 10-K. These financial statements and the schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the schedule 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 misstatements. An audit 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 presentation of the financial statements and schedule. 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

Also, in our opinion, the schedule when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth herein.

As more fully described in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company adopted the provisions of SFAS No. 123(R), “Share-Based Payment”.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Gastar Exploration Ltd.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated March 14, 2008 expressed an unqualified opinion thereon.

/s/ BDO Seidman, LLP

Dallas, Texas

March 14, 2008

 

F-2


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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

     As of December 31,  
     2007     2006  
     (in thousands)  
ASSETS     

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 85,854     $ 40,733  

Accounts receivable, net of allowance for doubtful accounts of $4.3 million and $626,000 respectively

     4,828       8,733  

Due from related parties

     904       4,394  

Prepaid expenses

     1,235       1,369  
                

Total current assets

     92,821       55,229  

PROPERTY, PLANT AND EQUIPMENT:

    

Natural gas and oil properties, full cost method of accounting:

    

Unproved properties, not being amortized

     69,844       89,658  

Proved properties

     247,372       181,362  
                

Total natural gas and oil properties

     317,216       271,020  

Furniture and equipment

     669       600  
                

Total property, plant and equipment

     317,885       271,620  

Accumulated depreciation, depletion and amortization

     (160,765 )     (110,794 )
                

Total property, plant and equipment, net

     157,120       160,826  

OTHER ASSETS:

    

Restricted cash

     1,074       45  

Deferred charges, net

     8,334       3,502  

Drilling advances

     2,251       9,137  

Other assets

     150       150  
                

Total other assets

     11,809       12,834  
                

TOTAL ASSETS

   $ 261,750     $ 228,889  
                
LIABILITIES AND SHAREHOLDERS’ EQUITY     

CURRENT LIABILITIES:

    

Accounts payable

   $ 12,001     $ 15,471  

Revenue payable

     6,770       3,464  

Accrued interest

     1,534       2,515  

Accrued drilling and operating costs

     2,810       5,680  

Other accrued liabilities

     5,311       3,120  

Due to related parties

     979       1,670  
                

Total current liabilities

     29,405       31,920  

LONG-TERM LIABILITIES:

    

Long-term debt

     132,685       93,803  

Asset retirement obligation

     4,391       4,218  

Liability to be settled by issuance of common shares

     —         606  
                

Total long-term liabilities

     137,076       98,627  

COMMITMENTS AND CONTINGENCIES (Note 16)

    

SHAREHOLDERS’ EQUITY:

    

Common stock, no par value, unlimited shares authorized, 208,194,570 and 194,965,436 shares issued and outstanding at December 31, 2007 and 2006, respectively

     249,980       225,986  

Additional paid-in capital

     14,366       10,418  

Accumulated other comprehensive loss—fair value of commodity hedging

     (480 )     —    

Accumulated other comprehensive loss—foreign exchange

     (29 )     (34 )

Accumulated deficit

     (168,568 )     (138,028 )
                

Total shareholders’ equity

     95,269       98,342  
                

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY

   $ 261,750     $ 228,889  
                

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

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

 

     For the Years Ended December 31,  
     2007     2006     2005  
     (in thousands, except share and per share data)  

REVENUES

   $ 34,565     $ 26,765     $ 27,442  

EXPENSES:

      

Production taxes

     765       1,478       1,062  

Lease operating expenses

     6,284       5,549       3,853  

Transportation and treating

     1,641       1,557       1,995  

Depreciation, depletion and amortization

     21,456       16,332       13,914  

Impairment of natural gas and oil properties

     28,514       56,280       8,697  

Accretion of asset retirement obligation

     281       234       109  

Mineral resource properties

     (133 )     450       65  

General and administrative expenses

     16,906       13,548       8,710  

Litigation settlement expense

     1,365       2,407       —    
                        

Total expenses

     77,079       97,835       38,405  
                        

LOSS FROM OPERATIONS

     (42,514 )     (71,070 )     (10,963 )

OTHER (EXPENSES) INCOME:

      

Interest expense

     (14,079 )     (15,599 )     (13,905 )

Early extinguishment of debt

     (15,684 )     —         (1,356 )

Investment income and other

     3,196       1,836       492  

Gain on sale of assets

     38,536       —         —    

Foreign transaction gain (loss)

     5       (6 )     40  
                        

LOSS BEFORE INCOME TAXES

     (30,540 )     (84,839 )     (25,692 )

Provision for income taxes

     —         —         —    
                        

NET LOSS

   $ (30,540 )   $ (84,839 )   $ (25,692 )
                        

NET LOSS PER SHARE:

      

Basic and diluted

   $ (0.15 )   $ (0.50 )   $ (0.20 )
                        

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:

      

Basic and diluted

     202,828,792       170,014,733       129,398,548  
                        

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

 

F-4


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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

 

    Common Stock   Additional
Paid-in
Capital
  Accumulated
Other
Comprehensive
Loss
    Accumulated
Deficit
    Total
Shareholders’
Equity
    Comprehensive
Loss
 
    Shares   Amount          
    (in thousands, except share data)  

Balance at December 31, 2004

  113,390,108   $ 45,347   $ 4,221   $ (95 )   $ (27,497 )   $ 21,976     $ —    

Exercise of stock options—cash

  3,721,300     707     —       —         —         707       —    

Exercise of stock
options—cashless

  2,214,888     —       —       —         —         —         —    

Issuance of shares—cash, net of offering costs of $ 3,312

  33,769,377     90,096     —       —         —         90,096       —    

Issuance of shares—acquisition

  8,023,827     23,000     —       —         —         23,000       —    

Issuance of shares—senior secured debt

  2,505,728     7,893     —       —         —         7,893       —    

Exercise of stock purchase warrants —cash

  207,814     413     —       —         —         413       —    

Exercise of stock purchase warrants —cashless

  841,224     —       —       —         —         —         —    

Stock based compensation

  —       —       2,288     —         —         2,288       —    

Foreign currency translation gain

  —       —       —       95       —         95       95  

Net loss

  —       —       —       —         (25,692 )     (25,692 )     (25,692 )
                                               

Total comprehensive loss

              $ (25,597 )
                   

Balance at December 31, 2005

  164,674,266     167,456     6,509     —         (53,189 )     120,776       —    

Issuance of shares—cash, net of offering costs of $2,169

  25,000,000     47,831     —       —         —         47,831       —    

Issuance of shares—acquisition

  548,128     2,116     —       —         —         2,116       —    

Issuance of shares—senior secured debt

  3,815,458     8,499     —       —         —         8,499       —    

Exercise of stock options —cashless

  905,636     —       —       —         —         —         —    

Exercise of stock purchase warrants —cash

  21,948     84     —       —         —         84       —    

Stock based compensation

  —       —       3,909     —         —         3,909       —    

Foreign currency translation loss

  —       —       —       (34 )     —         (34 )     (34 )

Net loss

  —       —       —       —         (84,839 )     (84,839 )     (84,839 )
                                               

Total comprehensive loss

              $ (84,873 )
                   

Balance at December 31, 2006

  194,965,436     225,986     10,418     (34 )     (138,028 )     98,342       —    

Issuance of shares—senior secured debt

  375,939     606     —       —         —         606       —    

Issuance of shares—cash, net of offering costs of $126

  11,757,195     23,388     —       —         —         23,388       —