Gastar Exploration Inc.
GASTAR EXPLORATION LTD (Form: 10-K, Received: 03/16/2009 17:26:30)
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, 2008

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
(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   NYSE Alternext US LLC
(formerly the 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 $2.56 per common share on the American Stock Exchange at the close of business on June 30, 2008 (the last business day of the registrant’s most recently completed second fiscal quarter) was $447,541,957.

As of March 12, 2009, there were 209,632,468 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, 2008

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 Regulation

   7
  

Environmental Regulation

   10
  

Industry Segments and Geographic Information

   15
  

Employees

   15
  

Corporate Offices

   16
  

Internet Website Access

   16

Item 1A.

  

Risk Factors

   16
  

Risk Factors Related to Our Business

   16
  

Risk Factors Related to Our Common Shares

   29

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

   32

Item 3.

  

Legal Proceedings

   33

Item 4.

  

Submission of Matters to a Vote of Security Holders

   33
   PART II   

Item 5.

  

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

   34
  

Market Information

   34
  

Shareholders

   34
  

Dividends

   34
  

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

   34

Item 6.

  

Selected Financial Data

   35

Item 7.

  

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

   35
  

Overview

   35
  

Critical Accounting Policies and Estimates

   37
  

Results of Operations

   41

 

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          Page
  

Liquidity and Capital Resources

   44
  

Off Balance Sheet Arrangements

   47
  

Contractual Obligations

   48
  

Commitments

   48
  

New Accounting Pronouncements

   49

Item 7A.

  

Quantitative and Qualitative Disclosure about Market Risk

   50
  

Commodity Price Risk

   50
  

Interest Rate Risk

   51
  

Currency Translation Risk

   51

Item 8.

  

Financial Statements and Supplementary Data

   51

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

   51

Item 9A.

  

Controls and Procedures

   51
  

Evaluation of Disclosure Controls and Procedures

   51
  

Management’s Report on Internal Control over Financial Reporting

   51
  

Changes in Internal Control over Financial Reporting

   52
  

Report of Independent Registered Public Accounting Firm

   53

Item 9B.

  

Other Information

   54
   PART III   

Item 10.

  

Directors and Executive Officers and Corporate Governance

   55

Item 11.

  

Executive Compensation

   55

Item 12.

  

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

   55

Item 13.

  

Certain Relationships and Related Transactions, and Director Independence

   55

Item 14.

  

Principal Accountant Fees and Services

   55
   PART IV   

Item 15.

  

Exhibits, Financial Statement Schedules

   56

SIGNATURES

   61

 

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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, as amended, (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:

 

   

The effect of receiving a “going concern” statement in our auditors’ report on our 2008 consolidated financial statements;

 

   

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 or repay or refinance debt upon maturity;

 

   

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;

 

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

 

   

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$”), 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 an independent energy company engaged in the exploration, development and production of natural gas and oil in the United States and Australia. Gastar pursues a strategy combining select higher risk, deep natural gas exploration prospects with lower risk coalbed methane (“CBM”) development. Gastar owns and operates exploration and development acreage in the deep Bossier gas play of East Texas and has commenced exploration operations in the Marcellus Shale in West Virginia and southwestern Pennsylvania. Gastar’s CBM activities are conducted within the Powder River Basin of Wyoming and Montana and on approximately 6.0 million gross acres controlled by us and our joint development partner in Australia’s Gunnedah Basin, located in New South Wales. We are a Canadian corporation incorporated in Alberta in 1987. We are publicly traded on the NYSE Alternext US LLC 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 20 productive wells, which we anticipate will grow to 22 wells over the next 12 months. We have identified numerous potential drilling locations on our current acreage position that provide opportunities under normal gas market conditions to increase production and cash flow through the drilling of high return deep Bossier wells.

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 by mid-2009. 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 valuable 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 have helped 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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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 have been in the Bossier play in the Hilltop area of East Texas approximately midway between Dallas and Houston in Leon and Robertson Counties, where we hold approximately 31,175 gross (15,099) net acres. 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, 2008, we had successfully completed 22 out of 24 wells in East Texas. During 2008, we completed a total of 4 gross (2.1 net) wells in the field. For 2009, we plan to drill up to 2 additional wells.

We recently completed the drilling of the Belin #1, a deep Bossier offset to the Wildman #3, with current gross production of approximately 22.7 MMcfd from two zones after an initial gross sales rate of 41.2 MMcfd. We have a 52% working interest and a 40% net revenue interest before payout in the Belin #1 well. We also have recently completed the Lone Oak Ranch #7 well, a middle Bossier offset to the Lone Oak Ranch #6. Current gross production from the Lone Oak Ranch #7 is approximately 4.9 MMcfd after an initial gross sales rate of 6.9 MMcfd. We have a 50% working interest and a 37.5% net revenue interest in the Lone Oak Ranch #7 well.

In November 2008, we released one of our two operated rigs. For 2009, we will continue our exploration program using only one rig for a portion of the year to conserve capital. In February 2009, we spud the Wildman Trust #5 well, an offset to the Wildman #3 well that had an initial production rate of 23.0 MMcfd. The Wildman Trust #5 well currently is drilling with total depth to be reached by late April 2009. At that time, we plan to release the remaining drilling rig and anticipate that we will incur a cost to do so.

For the year ended December 31, 2008, net production from the Hilltop area averaged 17.4 MMcfe per day. For the three months ended December 31, 2008, net production from the Hilltop area averaged approximately 18.1 MMcfe per day. At December 31, 2008, proved reserves attributable to the Hilltop area were approximately 56.8 Bcfe, or 89% of our total proved reserves.

Marcellus Shale—West Virginia and Southwestern Pennsylvania

The Marcellus Shale is Middle Devonian aged shale that underlies much of Pennsylvania, New York, Ohio, West Virginia and adjacent states. The depth of the Marcellus Shale and its low permeability have historically made the Marcellus an unconventional exploration target. Within the past few years, advances in two technologies, stimulation and horizontal drilling, have produced promising results in the Marcellus Shale. These developments have resulted in increased leasing and drilling activity in the area. In late 2007, we began acquiring an acreage position in the Marcellus Shale in West Virginia and southwestern Pennsylvania. As of December 31, 2008, our acreage position in the play was approximately 46,435 gross (42,251 net) acres, all of which is in the core, over-pressured area of the Marcellus play and most of which is in close proximity to wells being drilled in the Marcellus by other operators.

As of March 1, 2009, we have drilled 10 (9.1 net) shallow vertical wells, of which 5 are on production, and the remainder are scheduled to be on production during 2009. This shallow drilling program has been conducted primarily to hold certain leases by production, while we develop an exploration and development program for the deeper Marcellus Shale objective. We do not anticipate that we will drill any additional shallow wells until we secure a joint venture partner or until natural gas prices improve. We will continue to maintain our leases through renewals, extensions and renegotiations of drilling commitments.

 

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We are engaged in a process to identify a joint venture partner to help us develop this play and reduce our capital burden going forward. We anticipate that we will drill our first deep Marcellus Shale well in the second or third quarter of 2009, if we are able to secure a joint venture partner. Our overall drilling program has not yet been finalized pending establishing a relationship with an outside partner.

Coalbed Methane—Powder River Basin, Wyoming and Montana

We own an approximate 40% average working interest in approximately 40,808 gross (17,113 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 2008, we participated in the drilling of approximately 7 (3.5 net) CBM wells. As of December 31, 2008, we had an interest in 464 gross (202.8 net) productive CBM wells producing in the Basin. For the year ended December 31, 2008, our average net production from our CBM properties in the Powder River Basin was approximately 5.5 MMcf per day. We anticipate continuing our recompletion and drilling program in 2009. Our activity level will be influenced by gas prices in the area, which currently are significantly lower than our other operating areas.

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 (761,400 net) acres, located in the Gunnedah Basin of New South Wales (“NSW”), approximately 250 miles northwest of Sydney, Australia, near the town of Narrabri. We believe that the strategic location of PEL 238 and potential CBM reserves near the large natural gas markets in the Sydney-Newcastle-Wollongong area and the location relative to other developing gas and growing liquid natural gas (“LNG”) markets should create a competitive marketing advantage for the natural gas reserves that may be developed.

The PEL 238 development project is moving forward successfully with our first production expected by mid-2009. Beginning in 2008, we and Eastern Star Gas (“ESG”), our Australian joint venture partner and license operator, expanded our pilot production drilling program in the Bohena Project Area of PEL 238, with a 20-corehole exploration and appraisal drilling program. The results of the coreholes confirmed the presence of a thick Bohena coal seam developed to the south and east of the Bibblewindi pilot production area, as well as an area of thick, permeable gaseous coal in the northern portion of the license area. We currently are drilling the fourth of six wells that will comprise the first multi-lateral horizontal production area. This multi-lateral production project is located in the Bibblewindi project area and is expected to be completed in the next six weeks. We are also continuing with a 20-well corehole program to test and identify additional areas for CBM development. The Ederoi #1 corehole was successful and confirmed the presence of the targeted coal in an area approximately 26 miles north of the previous areas of concentration. The Bluehills #1 corehole was unsuccessful in the Maules Creek coal section but did confirm the shallower Hosskinson coal as present and permeable with good gas content and composition.

During 2007, we and ESG were approached by potential buyers with an interest in potentially contracting for up to 1.0 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

 

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agreement with Macquarie Generation would serve to underpin the development of the approximately 200 miles of pipeline infrastructure necessary to transport gas from the PEL 238 concession to Bayswater. An additional 100 miles 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 ESG had entered into a second MOU with Babcock & Brown 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.

Both Macquarie Generation and Babcock & Brown are continuing their feasibility studies as we continue with an active coring and production pilot drilling program to increase our proved and probable reserves to meet initial contract requirements.

In late June 2008, we announced, subject to certain approvals, an agreement to acquire a 35% interest in the Wilga Park Power Station in New South Wales, Australia from ESG, which owns the remaining 65% interest. This acquisition aligns both of our ownerships in PEL 238 and the Wilga Park Power Station. The power station is located approximately 20 miles north of the Bohena Project Area of PEL 238. The acquisition also includes a 35% working interest in Petroleum Production License 3, which contains the Coonarah conventional gas field. Upon the closing of our term loan in February 2009, we paid $3.1 million in cash to ESG, with an additional payment of $250,000 contingent upon the Wilga Park Power Station being successfully expanded to a capacity of seven megawatts (“MW”).

The Wilga Park Power Station currently has a capacity of 4.0 MW, with plans to gradually increase capacity up to 40.0 MW, as coal seam gas production from PEL 238 increases. Construction of a flowline to deliver gas from the PEL 238 production pilots to the power station is currently in progress and is expected to be completed by mid-2009. The power station will be the primary market for natural gas from PEL 238 until we begin fulfilling our supply arrangements under the two previously announced MOUs. We now expect first commercial sales to the plant late in mid-2009.

In July 2008, we and ESG entered into a Heads of Agreement (“HoA”) with the APA Group (“APA”), owner of the Central West and Moomba Sydney Gas Pipelines. Under the HoA, options for early delivery of coal seam gas from PEL 238 into NSW gas market are to be investigated. Under the HoA, it is anticipated that coal seam gas would be initially delivered to New South Wales gas markets via APA’s Central West Pipeline, with APA’s NSW pipeline system to subsequently be expanded as gas production and markets grow. By matching gas production, pipeline and market requirements in this manner, we and ESG believe we can minimize capital requirements, while realizing favorable gas transportation tariffs.

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”.

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

We hold approximately 1.9 million gross (664,000 net) acres in PEL 433 and approximately 1.9 million gross (669,000 net) acres in PEL 434. PEL 433 and PEL 434 are located south of PEL 238, where we and ESG are developing the Gunnedah Basin Gas Project. Coal evaluation core-hole drilling completed during the 1970s and 1980s by the NSW government identified the distribution and thickness of the coal measures within a portion

 

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of PEL 433. The Hoskissons Coal Seam is believed to be approximately 13 to 20 feet 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 ESG under which we have earned a 35% working interest in the PEL 433 and PEL 434. Under the terms of the Farm-In Agreement, we paid the costs of a two core-hole program on PEL 433 and the related costs of the evaluation of the coal reservoirs intersected by the core-holes. A two corehole drilling program, designed to evaluate the coal seam gas permeability, gas content and gas composition, was completed in early 2008. The results from these wells showed good coal development, gas composition and excellent permeability in the area. Gas contents were low due to the shallow depth of the coal. Further investigation is underway to identify areas with improved gas content. Analysis of the core samples is continuing. This two-corehole program fulfilled the first year capital expenditure commitment for PEL 433.

The first acreage expirations in PEL 433 and PEL 434 are set to occur in 2011 and 2010, respectively. We and ESG plan to submit a renewal application including a drilling program to meet work commitment during the term of the renewal. As is customary, we and ESG anticipate that a renewal will necessitate a relinquishment of up to 25% of our current acreage. There is no assurance that these renewals will be obtained.

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

In June 2008, we and GeoStar Corporation, a former major shareholder, entered into a settlement agreement involving a number of disputes including our right to an assignment of our interest in EL 4416, located in Victoria, Australia. As part of the settlement, we acknowledged GeoStar’s clear title to EL 4416, and, accordingly, we have no rights in this property. As of the settlement date, EL 4416 had no attributable proved reserves or production.

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. Although some industry observers have indicated that long-term demand for natural gas is increasing because of rising demand for natural gas to fuel power generation and meet increasing environmental requirements, natural gas currently is selling at significantly lower prices than experienced in recent years.

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. Our West Virginia production is sold on the spot market to regional pipeline 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

 

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currently not served by any natural gas infrastructure. The initial gas market for PEL 238 natural gas is anticipated to be the Wilga Park Power Station, jointly owned by us and ESG and operated by ESG. Although there currently is no pipeline from the existing and planned CBM project areas, we and ESG currently are constructing the first gathering system and pipeline in the area, which is anticipated to be completed by mid-2009.

The longer term market for PEL 238 natural gas is considered to be future gas-fired power generation facilities in NSW, the industrial and residential markets in the Sydney-Newcastle-Wollongong areas of NSW and possible LNG export. Recent announcements of 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 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 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 and 434 concessions. In addition, a potential gas supply and purchase agreement with Macquarie Generation would serve to underpin the development of the approximately 200 miles of pipeline infrastructure necessary to transport gas from the PEL 238 concession to Bayswater. An additional approximate 100 miles 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”.

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, the Company entered into formal agreements with ETC Texas Pipeline, Ltd. (“ETC”) for the gathering, treating, purchase and transportation of the Company’s 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 the Company 50 MMcfd of treating capacity and 120 MMcfd of gathering capacity. The Company has 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 the Company’s production equals 85% of the then existing treating and gathering capacity for a 30 day period. The Company may at any time elect to have its 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, the Company must furnish to ETC information that reasonably demonstrates that its 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, the Company has access of 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. The Company has the option to sell and ETC has the obligation to buy, up to 150 MMcfd of the Company’s Hilltop production at delivery points upstream of ETC’s gathering and treating facilities. The Company does 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 2008, ETC and Enserco Energy, Inc. (“Enserco”) accounted for 79% and 19% of our natural gas and oil revenues, respectively. During 2007, ETC and 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. 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 .    The natural gas industry is extensively regulated by numerous federal, state and local authorities. 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 made 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.

The availability, terms and cost of transportation can significantly affect sales of natural gas. 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 offer available firm transportation capacity on an open access, non-discriminatory basis to 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.

State laws and regulations generally govern the gathering and intrastate transportation of natural gas. Natural gas gathering systems in the states in which we operate are generally required to offer services on a non-discriminatory basis, and are subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without discrimination in favor of one producer over another producer or one source of supply over another source of supply.

Under the Energy Policy Act of 2005, or EPAct 2005, Congress made it unlawful for any entity, including otherwise non-jurisdictional producers of natural gas, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services regulated by the FERC that violates the FERC’s rules. FERC’s rules implementing the provision of EPAct of 2005 make it unlawful for any entity, directly or indirectly, to use or employ any device, scheme, or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation.

Pursuant to authority granted to FERC by EPAct, FERC has also put in place additional regulations intended to prevent market manipulation and to promote price transparency. For example, FERC has imposed new rules requiring wholesale purchasers and sellers of natural gas to report to FERC certain aggregated volume and other purchase and sales data for the previous calendar year. While EPAct 2005 reflects a significant expansion of the FERC’s enforcement authority, we do not anticipate that we will be affected by that statute any differently than other producers of natural gas.

 

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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 .    The oil industry is also extensively regulated by numerous federal, state and local authorities. Prices for crude oil and condensate are not currently regulated and are made at market levels. 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 extensive regulation under a wide range of state and federal statutes, rules, orders and regulations. State and federal statutes and regulations require, among other things, 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 and oil wells; the spacing of wells; and the plugging and abandonment of wells and removal of related production equipment. These and other regulations can limit the amount of the natural gas and oil we can produce from our wells, limit the number of wells we can drill, 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 or Territory Laws and Regulations .    The regulation of the activities of participants in the natural gas and oil industry (the “petroleum industry”) in Australia is similar to that of the United States, in that regulatory controls are imposed at both the State, Territory 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 or Territory 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, including the petroleum industry. 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.

 

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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 or Territory 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 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 in some circumstances.

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.

 

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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 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

 

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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 and state waters, including wetlands. In addition, depending on the location, discharges from or the use of water in our operations may be subject to regulation by regional or local regulatory authorities. Under the CWA and OPA, any unpermitted release of pollutants from operations could cause us to become subject to the costs of remediating a release; administrative, civil or criminal fines or penalties; or OPA specified damages, such as damages for loss of use and natural resource damages. In addition, in the event that spills or releases of produced water from natural gas and oil production operations were to occur, we would be subject to spill notification and response requirements under the CWA or the equivalent state regulatory program. Depending on the nature and location of these operations, spill response plans may also have to be prepared.

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

 

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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 that 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.

Endangered Species Act.      The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered or threatened species or their habitats. While some of our operations may be located in or near areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

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.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is considering legislation to reduce emissions of greenhouse gases. President Obama has expressed support for legislation to restrict or regulate emissions of greenhouse gases. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. 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. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court’s decision in Massachusetts . In the notice, EPA evaluated the potential regulation of greenhouse gases under the

 

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Clean Air Act and other potential methods of regulating greenhouse gases. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. 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.

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 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 the National Greenhouse and Energy Reporting Act 2007 (Cth) , 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 Carbon Pollution Reduction Scheme (“CPRS”), as it will be known, which is expected to commence on July 1, 2010.

The Australian Government released its final policy on the design of the CPRS in December 2008. In December 2008, the Australian Government also confirmed a national emissions reduction target of between 5% and 15% of 2000 levels by 2020. Draft legislation for the CPRS is expected to be released for public comment in February 2009. As the detail of the CPRS is not yet finalized, we are only able to assess the likely impact of the CPRS on our operations in Australia.

The CPRS will be a “cap and trade scheme” in which total emissions are capped by the number of permits issued by the Government. Permits will be auctioned (with ‘free’ permits allocated to certain emissions-intensive trade-exposed industries). It is possible that upstream gas producers may be entitled to receive some free permits. Trading in permits will allow the market to find the cheapest way to meet any necessary emission reductions.

Each year, an entity to which the CPRS applies will need to surrender a permit for every ton of emissions that they produced in that year. CPRS obligations will apply to entities with operational control of a facility that has direct emissions of 25,000 tons of carbon dioxide equivalent gas (CO 2 -e) a year or more.

Under the CPRS, upstream gas companies like Gastar, will be responsible for holding permits for the emissions directly arising from the gas exploration and production activities, over which they have operational control. Principally, this will be fugitive emissions and emissions from flaring gas in association with our exploration or production activities. As we are not the operator of our New South Wales project, responsibility for managing compliance with the CPRS, to the extent it applies, will not lie with us. However, the costs of the CPRS on the project will be borne by us, in proportion to our interest in the project.

Gas from our New South Wales project is currently committed to power generators operating in the vicinity of our operations. Under the CPRS, these power generators will be responsible for holding permits in respect of the emissions associated with the use of our gas. It is likely that a gas producer will only have a responsibility to hold permits in relation to the downstream use of gas if its sells directly to small industrial or commercial users of gas.

It has been estimated that a permit to emit one ton of CO 2 -e will trade at approximately AUD20–25 at the commencement of the CPRS.

 

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The legislation regulating environmental assessment at a commonwealth level is the Environmental Protection and Biodiversity Conservation Act 1999 (Cth.) (the “Act”). The 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 adds 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 government of New South Wales has a suite of legislation regulating environmental matters in the State. Generally speaking, onshore natural gas and oil projects in New South Wales 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 New South Wales 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 requiring remediation and reinstatement obligations for the site during the course of operations and following closure of the project.

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 Territories (including 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 12, 2009, we had 22 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 its employees to be good.

 

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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 $18,151 through October 2010 and an additional 2,022 square feet at a monthly rental of $5,581 through August 2009.

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 Act 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 Securities and Exchange Commission (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.

 

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.

Our ability to successfully execute and maximize our business plan and meet our scheduled debt maturities during 2009 is dependent on obtaining adequate financing or selling significant assets, which we may not be able to implement successfully.

Global financial markets and economic conditions have been, and continue to be, severely disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. Significant write-offs in the financial services sector, the re-pricing of credit risk, concerns about overall deflation and its effects on commodity prices and the possibility of a deepening world recession have made, and will likely continue to make, it difficult for companies to raise funds in the financial markets.

 

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Our 2009 capital expenditures under our current business plan are estimated to total approximately $71.2 million. Based on our revised 2009 capital plan, our current cash on hand, and internally generated cash flow, we project that over the next twelve months we will need to raise an additional $95.0 million in order to fund our exploration and development activities and working capital needs, including the payment of $52.1 million in scheduled debt maturities in 2009 but excluding the $99.6 million (net of unamortized discount) of our 12¾% senior secured notes that are due in 2012 but classified as current portion of long-term debt due to liquidity concerns and the potential for acceleration of maturity as a result of cross default provisions. Of the $52.1 million in 2009 maturities, the maturity on October 15, 2009 of $18.9 million due under our revolving credit facility may be automatically extended to December 1, 2010 if we can demonstrate to the administrative agent’s satisfaction our ability to repay or refinance all of the $30.0 million principal amount of outstanding convertible senior unsecured subordinated debentures due November 20, 2009, or convertible subordinated debentures. Our ability to raise additional capital will principally depend on the status of the capital and loan markets and our results of operations 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. Our loan covenants significantly restrict our ability to (i) issue new debt to refinance our 2009 maturities and (ii) repay our $30.0 million convertible subordinated debentures with asset sale proceeds.

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. If we are unable to pay any significant portion of our 2009 current maturities when due, whether at its scheduled repayment date or upon any earlier acceleration following any breach of a loan covenant, such non-payment will constitute a default under the indenture governing our 12  3 / 4 % senior secured notes, our revolving credit facility and our term loan, which could result in the acceleration of maturity of all of our debt.

There is substantial doubt about our ability to continue as a going concern.

Our independent registered public accounting firm has issued an opinion on our consolidated financial statements that states that the consolidated financial statements were prepared assuming we will continue as a going concern and further states that our need to refinance or raise capital to retire debt maturing in 2009 raises substantial doubt about our ability to continue as a going concern. Our consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. Our plans concerning these matters are discussed in Note 3 to the accompanying audited consolidated financial statements. Our future is dependent on our ability to successfully repay or refinance our current maturities and address our other liquidity issues. If we fail to do so for any reason, we would not be able to continue as a going concern and could potentially be forced to seek relief through a filing under the U.S. Bankruptcy Code.

Our inability to meet a financial covenant contained in our bank revolving credit facility or our term loan may adversely affect our liquidity, financial condition or results of operations.

We are subject to certain financial covenants we are required to maintain under our revolving credit facility and our term loan related to our working capital, cash flow and general and administrative expenses. The financial covenants included in our term loan are similar to financial covenants in our revolving credit facility.

Adverse market conditions decreased natural gas prices in the second half of 2008 and early 2009, which have significantly reduced our cash flow and adversely affected our ability and the cost of raising capital. At December 31, 2008 we reported $151.7 million as current portion of long-term debt, of which $52.1 million is scheduled to mature during 2009, a working capital deficit of $157.2 million and were not in compliance with the current ratio test under our revolving credit facility. Due to liquidity concerns and the potential for acceleration of maturity as a result of cross default provisions, the current maturities and working capital deficit at December 31, 2008 include $99.6 million of 12  3 / 4 % senior secured notes due 2012. On February 16, 2009, we entered into a waiver and second amendment which provides a waiver of any past or present breach of the working capital, or current ratio, covenant effective until March 31, 2009. On March 12, 2009, we entered into a waiver and third amendment which provides for the waiver of a breach of the current ratio test under the revolving credit facility

 

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and any future breach of the current ratio covenant as determined as of the end of any quarter of our fiscal year ending December 31, 2009. The waiver and third amendment also provides for the waiver of a breach of a covenant under the revolving credit facility resulting from our auditors’ issuance of a going concern statement in its report on our 2008 consolidated financial statements.

There is no assurance we will be in compliance with our financial covenants at March 31, 2009 or at the end of future fiscal quarters. If we breach a financial covenant in the future and we are unable to cure such violation or obtain waivers from our lenders under the revolving credit facility within the applicable cure periods, such violation will constitute an event of default under the revolving credit facility, and our lender could terminate any commitments it had to make available further funds, accelerate the due dates for the payments of all outstanding indebtedness and exercise its remedies as a secured creditor with respect to the collateral securing the revolving credit facility, which is substantially all of our natural gas and oil properties. A default under the revolving credit facility will cause cross defaults in our other credit facilities, which may result in the acceleration of maturities of all of our debt.

If the counterparties to the derivative instruments we use to hedge our business risks default or fail to perform, we may be exposed to risks we had sought to mitigate, which could materially adversely effect our financial condition and results of operations.

We use hedges to mitigate our natural gas price risk with counterparties. If our counterparties fail or refuse to honor their obligations under these derivative instruments, our hedges of the related risk will be ineffective. This is a more pronounced risk to us in view of the recent stresses suffered by financial institutions. Such failure could have a material adverse effect on our financial condition and results of operations. We cannot provide assurance that our counterparties will honor their obligations now or in the future. A counterparty’s insolvency, inability or unwillingness to make payments required under terms of derivative instruments with us could have a material adverse effect on our financial condition and results of operations. At the date of filing of this Form 10-K, our only counterparty was BP Corporation North America.

Natural gas and oil prices are volatile and further declines in natural gas and oil prices will continue to significantly and negatively 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.

 

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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.

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, 2008, approximately 76% of our production was priced based on the Katy Hub (“Katy”) basis point, and 23% was priced on the CIG basis point. In 2007, natural gas prices based on CIG were 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 was attributed primarily to limitations in available pipeline capacity for natural gas deliveries out of the Rocky Mountain area. While this volatility has been alleviated partially by completion of a major pipeline system in January 2008, CIG natural gas prices continue to currently trade approximately $1.60 per MMBtu less than Henry Hub prices and may decline further if supplies of natural gas in the Rocky Mountains continue to increase. Our West Virginia natural gas production is priced using the Columbia Gas Appalachia Pool. At December 31, 2008, the Katy hub basis was $5.710, compared to our key basis point pricing of $5.235 per MMBtu at the Katy Hub, $4.605 per MMBtu for CIG and $6.095 for the Columbia Appalachia Pool. Low natural gas prices in any or all of the areas where we operate would negatively impact our financial condition and results of operations.

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. Further, 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

 

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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 $5.4 million, $30.5 million and $84.8 million for the years ended December 31, 2008, 2007 and 2006, 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. Our failure to achieve profitability in the future could materially adversely affect our ability to raise additional capital, continue our exploration and development program and meet our 2009 debt maturities.

We have a substantial amount of long-term debt, and debts maturing in 2009, 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, 2008, we had total debt at maturity of $152.1 million of which $52.1 million matures in 2009. Our level of indebtedness affects our operations in several ways, including the following:

 

   

We may be unable to raise sufficient capital to repay or refinance $52.1 million of debt maturing in 2009, resulting in one or more defaults which would trigger automatic cross-defaults and the acceleration of maturities of all of our debts;

 

   

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

 

   

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

 

   

We may be unable to withstand the current economic downturn and any future adverse developments in our industry or the economy in general, especially declines in natural gas and oil prices;

 

   

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, reacting to and withstanding recent and future 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 need to incur substantially more debt in the future. Although the indenture governing our revolving credit facility, term loan and the 12  3 / 4 % senior secured notes contain restrictions on our incurrence of additional indebtedness, including prohibitions on our incurrence of new debt senior or pari passu to such debts, these restrictions are subject to a number of qualifications and exceptions, and under certain circumstances, additional indebtedness incurred in compliance with these restrictions could be substantial.

 

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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.

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;

 

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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.

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.

Half 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, 2008, approximately 50% 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, 2008 assumes that we will spend significant development capital expenditures to develop these reserves, including an estimated $33.0 million and $12.3 million in 2009 and 2010, 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 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 operations may incur substantial liabilities in connection with climate change legislation and regulatory initiatives.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere. In response to such studies, the U.S. Congress is considering legislation to reduce emissions of greenhouse gases and more than one-third of the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. Also, the U.S. Supreme Court’s holding in its 2007 decision, Massachusetts, et al. v. EPA , that carbon dioxide may be regulated as an “air pollutant” under the Federal Clean Air Act could result in future regulation of greenhouse gas emissions from stationary sources, if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions and could have a material adverse effect on our business or demand for the natural gas we produce.

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

 

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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, 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.

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.

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;

 

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Pipeline ruptures or spills;

 

   

Natural disasters; and

 

   

Releases of toxic natural gas.

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

 

   

Injury or death;

 

   

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

 

   

Pollution and other environmental damage;

 

   

Regulatory investigations and penalties;

 

   

Suspension of operations; and

 

   

Repair and remediation costs.

We could also be responsible for environmental damage caused by previous owners of property from whom we purchased leases. 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 and 89% of our total proved reserves as of and for the year ended December 31, 2008 were attributable to our properties in East Texas. Any disruption in production, development of proved reserves, or our ability to process and sell natural gas from this area would have a material adverse effect on our results of operations or reduce future revenues.

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 $5.5 million to $8.3 million, with a corresponding reduction in our cash flow. Moreover, an unexpected delay in developing proved reserves in this area due to capital constraints or changes in development plan could reduce future revenues.

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.

 

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There are a limited number of natural gas purchasers and transporters in the Hilltop area of 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, 2008, 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 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 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 West Virginia and southwestern Pennsylvania, key issues to development include limited pipeline infrastructure and access, water access and disposal issues to support operations, and limited industry services. All of these factors could have an adverse effect on our ability to effectively conduct exploration and development activities.

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 Wilga Park Power Station, located near the town of Narrabri, New South Wales. A gathering and transmission pipeline is being built to serve this facility. Access to a larger electricity facility will require construction of a pipeline of approximately 200 miles to reach PEL 238 with an additional approximate 100 miles of pipeline infrastructure required to access the natural gas markets in the Sydney-Newcastle-Wollongong markets. The capital costs for this latter project, if deemed feasible, would be substantial in order to realize the value of any identified reserves and construction would require significant amounts of time.

 

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

Coalbed 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.

Coalbed methane exploration in New South Wales is conducted under a Petroleum Exploration License 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 license or PEL could adversely affect our exploration and development plans, results of operations, financial condition or cash flows.

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. 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,

 

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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 facility or well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Future acquisitions could pose additional risks to our operations and financial results, including:

 

   

Problems integrating the purchased operations, personnel or technologies;

 

   

Unanticipated costs;

 

   

Diversion of resources and management attention from our exploration business;

 

   

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

 

   

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

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

Other companies operate some of the properties in which we have an interest. As a result, we have a limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could 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.

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.

Currently, we have entered into hedges representing 67% of our 2009 U.S. projected production of natural gas. Although these hedges may partially protect us from by declines in natural gas prices, the use of these arrangements also 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. Currently, we have only minimal exposure to Canadian currency fluctuations, as almost all of our current revenues and expenses are in U.S. dollars.

 

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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 and chief financial 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, 2008, Chesapeake Energy Corporation owned approximately 16.2% 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.

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

Two of our directors, one of whom resides in Canada, are citizens of 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.

Risk Factors Related to Our Common Shares

Our common shares are unsecured equity interests in the Company.

As an equity interest, our common shares are not secured by any of our assets. Therefore, in the event we are liquidated, the holders of our common shares will receive a distribution only after all of our secured and unsecured creditors have been paid in full. In the event of a liquidation, there can be no assurance that we will have sufficient assets after paying our secured and unsecured creditors to make any distribution to the holders of our commons 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

 

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beyond our control. Information about the market price of our common shares for 2007 and 2008 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 an 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.

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 NYSE Alternext US LLC 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 affected 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.

 

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;

 

   

Marcellus Shale in West Virginia and southwestern Pennsylvania;

 

   

Powder River Basin in Wyoming and Montana; and

 

   

Gunnedah Basin in New South Wales, Australia.

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,
         2008            2007    

Production:

     

Natural gas (MMcf)

     8,482      6,576

Oil (MBbl)

     5      8

Total (MMcfe)

     8,510      6,621

Natural gas (MMcfd)

     23.2      18.0

Oil (MBod)

     0.0      0.1

Total (MMcfed)

     23.3      18.1

Average sales prices before hedging activity:

     

Natural gas (per Mcf)

   $ 6.92    $ 5.18

Oil (per Bbl)

   $ 98.39    $ 66.17

Average sales prices after hedging activity (1):

     

Natural gas (per Mcf)

   $ 6.63    $ 5.18

Oil (per Bbl)

   $ 98.39    $ 66.17

Selected data per Mcfe:

     

Lease operating, transportation and selling expenses

   $ 1.28    $ 1.32

General and administrative expenses

   $ 1.68    $ 2.13

Depreciation, depletion and amortization of natural gas and oil properties

   $ 2.87    $ 3.24

 

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

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. “Under evaluation” 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,
     2008    2007
     Gross    Net    Gross    Net

Exploratory wells:

           

Productive

   9    7.2    4    2.2

Non-productive

   —      —      1    0.3

Under evaluation

   —      —      10    7.5
                   

Total

   9    7.2    15    10.0
                   

Development wells:

           

Productive

   9    4.6    31    14.8

Non-productive

   —      —      —      —  
                   

Total

   9    4.6    31    14.8
                   

 

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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, 2008. Gross acreage represents the total number of acres in which we own a working interest. Net acreage represents our proportionate working interest resulting from our ownership in gross acres.

 

     Undeveloped Acreage    Developed Acreage
     Gross    Net    Gross    Net

United States:

           

Hilltop area, East Texas

   22,527    10,162    8,648    4,937

Marcellus Shale, West Virginia and Pennsylvania

   42,585    38,401    3,850    3,850

Powder River Basin, Wyoming and Montana

   22,116    9,491    18,692    7,623

Other

   2,448    2,448    —      —  
                   

Total United States

   89,676    60,502    31,190    16,410
                   

Australia:

           

Gunnedah Basin, New South Wales

   5,984,299    2,094,505    —      —  
                   

Total Australia

   5,984,299    2,094,505    —      —  
                   

Productive Wells

The following table sets forth our working interest ownership in productive wells in the areas indicated as of December 31, 2008. 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 currently are capable of producing natural gas or oil. 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

   20    12.6    —      —      20    12.6

Appalachia, West Virginia and Pennsylvania

   37    35.3    —      —      37    35.3

Powder River Basin, Wyoming and Montana

   464    202.8    —      —      464    202.8
                             

Total United States

   521    250.7    —      —      521    250.7
                             

As of December 31, 2008, we had no commercially productive wells in Australia.

Natural Gas and Oil Reserves

Our estimated total net proved reserves of natural gas and oil as of December 31, 2008 and the present values of estimated future net revenues attributable to those reserves as of that date 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

 

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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, 2008
     Producing    Non-producing    Undeveloped    Total

Natural gas (MMcf)

     31,999      8,240      23,446      63,685

Oil (MBbls)

     12      —        —        12

Total proved reserves (MMcfe)

     32,069      8,240      23,446      63,755

Standardized measure of discounted future net cash flow (000)

   $ 73,227    $ 14,712    $ 22,151    $ 110,090

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, 2008. 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, 2008
     Gas ($/MMBtu)    Oil ($/Bbl)

Production:

     

Hilltop Area, East Texas

   $ 5.235    $ 41.00

Marcellus Shale, West Virginia and Pennsylvania

   $ 6.095    $ 41.00

Powder River Basin, Wyoming and Montana

   $ 4.605    $ 41.00

The weighted average natural gas and oil prices after basis adjustments used in our reserve valuation as of December 31, 2008 were $4.56 per Mcf and $42.36 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, 2008. 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, 2008, 2007 and 2006 and the changes in quantities and standardized measure of such reserves for each of the three years then ended, see Note 22—Supplemental Oil & Gas Disclosures—Unaudited to our consolidated financial statements, which begin on page F-1.

 

Item 3. Legal Proceedings

Information about our legal proceedings is set forth in Note 15—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, 2008, 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 NYSE Alternext US LLC (formerly 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 NYSE Alternext US LLC and as reported on the Toronto Stock Exchange for the periods presented.

 

     NYSE
Alternext US LLC (1)
   Toronto
Stock Exchange
         High            Low        High    Low

2008:

           

Fourth quarter

   $ 1.30    $ 0.08    CDN$ 1.34    CDN$ 0.30

Third quarter

   $ 2.72    $ 1.16    CDN$ 2.91    CDN$ 1.29

Second quarter

   $ 2.75    $ 1.15    CDN$ 3.00    CDN$ 1.21

First quarter

   $ 1.51    $ 0.90    CDN$ 1.47    CDN$ 1.47

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

 

(1) Prior to October 1, 2008, our common shares were traded on the American Stock Exchange. Effective that date, the American Stock Exchange was acquired by the NYSE Alternext US LLC.

The last reported sale prices of our common shares on the NYSE Alternext US and the Toronto Stock Exchange on March 10, 2008 were $0.46 and CDN$0.57, respectively.

Shareholders

As of March 10, 2008, there were 528 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 revolving credit facility, term loan and 12  3 / 4 % senior secured notes 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

All of our equity securities sold during the year ended December 31, 2008 that were not registered under the Securities Act of 1933, as amended, have been previously reported on a Quarterly Report on Form 10-Q or a Current Report on Form 8-K.

 

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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,  
     2008     2007     2006     2005     2004  
     (in thousands, except per share data)  

Consolidated Statements of Loss:

          

Revenues

   $ 63,219     $ 34,565     $ 26,765     $ 27,442     $ 6,059  

Loss from operations

   $ (976 )   $ (42,514 )   $ (71,070 )   $ (10,963 )   $ (9,587 )

Net loss

   $ (5,361 )   $ (30,540 )   $ (84,839 )   $ (25,692 )   $ (12,776 )

Basic and diluted loss per share

   $ (0.03 )   $ (0.15 )   $ (0.50 )   $ (0.20 )   $ (0.12 )

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

     207,099       202,829       170,015       129,399       111,374  

Consolidated Balance Sheet:

          

Property plant and equipment, net

   $ 252,527     $ 157,120     $ 160,826     $ 165,347     $ 56,564  

Total assets

   $ 288,437     $ 261,750     $ 228,889     $ 240,128     $ 84,442  

Long-term liabilities

   $ 5,095     $ 137,076     $ 98,627     $ 105,410     $ 60,668  

Total shareholders’ equity

   $ 101,582     $ 95,269     $ 98,342     $ 120,776     $ 21,976  

 

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 and have been prepared assuming that we will continue as a going concern. As discussed in Note 3 to the consolidated financial statements, our need to refinance or raise capital to retire debt maturing in 2009 raises substantial doubt about our ability to continue as a going concern. Management’s plans concerning these matters are also discussed in Note 3 to our consolidated financial statements included in this report. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. 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, inability to access the capital markets, economic and competitive conditions, regulatory changes, the impact of acquisitions, 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.

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. Gastar pursues a strategy combining select higher risk, deep natural gas exploration prospects with lower risk coalbed methane (“CBM”) development. Gastar owns and operates exploration and development acreage in the deep Bossier gas play of East Texas and has commenced exploration operations in the Marcellus Shale play in West Virginia and southwestern Pennsylvania. Gastar’s CBM activities are conducted within the Powder River Basin of Wyoming and Montana and on approximately 6.0 million gross acres controlled by us and our joint development partner in the Gunnedah Basin, located in New South Wales, Australia.

 

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Our major domestic assets consist of approximately 31,175 gross (15,099 net) acres in the Bossier play in the Hilltop area of East Texas, approximately 46,435 gross (42,251 net) acres in the Marcellus Shale in West Virginia and southwestern Pennsylvania and approximately 40,808 gross (17,113 net) acres in the Powder River Basin of Wyoming and Montana. During the past three years, we spent approximately $245.9 million in acreage, seismic, capitalized interest, reserve acquisition and exploratory and development drilling on this acreage. 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, however, 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 and in the Marcellus Shale, 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 NSW. The PEL 238 development project is moving forward successfully with our first production expected by mid-2009.

In February 2009, we acquired a 35% interest in the Wilga Park Power station in New South Wales, from Eastern Star Gas, our joint venture partner, which owns the remaining 65% interest. This acquisition aligns both of our ownerships in PEL 238 and the Wilga Park Power Station. The power station is located approximately 20 miles north of the Bohena Project Area of PEL 238. Upon the closing of our term loan, we paid $3.1 million in cash to Eastern Star Gas, with an additional payment of $250,000 contingent upon the Wilga Park Power Station being successfully expanded to a capacity of seven megawatts. The power station currently is the primary market for natural gas from PEL 238. We now expect first commercial sales to the plant by mid-2009.

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 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 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.

 

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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 attributable to proved reserves, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities.

Capitalized drilling costs, 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 an impairment has occurred. When proved reserves are assigned or a property is considered to be impaired, the cost of the property or the amount of the impairment is added to the 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.

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,

 

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development costs, and workover costs, all of which may 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. A ceiling impairment of $14.2 million was required at December 31, 2008. 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 December 31, 2008 was $4.56 per Mcf.

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. A 10% decrease in prices would have resulted in an additional ceiling impairment of approximately $17.8 million. A 10% increase in prices used would have increased our 10% discounted present value by $18.9 million, resulting in a ceiling cushion of approximately $4.7 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, 2008 by approximately $533,000, while a 10% decrease in reserves would have increased our depletion expense by approximately $647,000.

Unproved Property Impairment

Nature of Critical Estimate Item.     We utilize 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-by-field basis. If the results of an assessment indicate that an unproved property is impaired, the amount of impairment is subtracted from proved natural gas and oil property costs to be amortized.

Assumptions/Approach Used.     At December 31, 2008, we had $141.9 million allocated to unproved property costs, which was comprised primarily of unevaluated acreage costs. The unproven property costs 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 impairment expense by approximately $14.2 million for the year ended December 31, 2008.

 

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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.     There are many variables in estimating AROs. We primarily use the remaining estimated useful life from the year end independent reserve 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 cost to be significantly different than a normal abandonment, we use this estimate. The resulting estimate, after application of an inflation factor and a discount factor, 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, Australia and (2) capitalized interest on borrowed funds used to invest in unproven natural gas and oil properties not being 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 capitalized interest incurred are our revolving credit facility and our 12  3 / 4 % senior secured notes. The interest to be capitalized for any period is derived by multiplying the average 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.

 

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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-based plans 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 123R, “Share-Based Payment”, using the modified-prospective method. Under that method, compensation cost for 2008, 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 123R.

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 restricted common shares grants is the closing price on the day prior to the grant times the number of restricted common shares granted. The total 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-Merton model requires various highly judgmental assumptions including volatility, expected option life and forfeiture rate. If any of the assumptions used in the Black-Scholes-Merton 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 during the period indicated:

 

     For the Year
Ended
December 31, 2007
 

Expected volatility

   44.4% – 44.7 %

Expected life (in years)

   6.25  

Expected forfeitures

   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, 2008 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, 2008 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, 2008. There were no stock option grants in 2008.

Fair Value

We maintain a commodity-price risk-management strategy that uses derivative instruments to minimize significant fluctuations that may arise from volatility in commodity prices. We use natural gas costless collars, index swaps, basis swaps and put options to hedge commodity price risk. Based on our projections, approximately 37% of our 2009 estimated natural gas production was hedged as of December 31, 2008. We carry all derivative assets and liabilities at fair value.

 

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We determine the fair market values of financial instruments based on the fair value hierarchy established in SFAS No. 157. We utilize third-party broker quotes to access the reasonableness of forward commodity prices, volatility factors, discount rates and the valuation techniques used to measure the fair value of our derivative assets and liabilities, which are all traded in the over-the-counter market. We incorporate counterparty credit risk and our own credit risk within the fair value measurement of derivative assets and liabilities, respectively. Credit adjustments, if any, are applied to fair value measurements based on the historical default probabilities of the respective credit ratings assigned to the debt of our counterparties and to us, as published by the independent credit rating agencies.

We currently utilize derivative instruments which are placed with a multinational energy company of high credit quality. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparty in the derivative contracts; however, the Company believes credit risk is minimal and does not anticipate such nonperformance

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,
         2008            2007            2006    

Production:

        

Natural gas (MMcf)

     8,482      6,577      4,646

Oil (MBbl)

     5      7      12

Total (MMcfe)

     8,510      6,621      4,716

Natural gas (MMcfd)

     23.2      18.0      12.7

Oil (MBod)

     0.0      0.1      0.2

Total (MMcfed)

     23.3      18.1      12.9

Average sales prices before hedging activity:

        

Natural gas (per Mcf)

   $ 6.92    $ 5.18    $ 5.60

Oil (per Bbl)

   $ 98.39    $ 66.17    $ 64.66

Average sales prices after hedging activity:

        

Natural gas (per Mcf) (1)

   $ 6.63    $ 5.18    $ 5.60

Oil (per Bbl)

   $ 98.39    $ 66.17    $ 64.66

 

(1) We had no hedging instruments on 2007 or 2006 natural gas volumes.

Year Ended December 31, 2008 compared to Year Ended December 31, 2007

Revenues.     Substantially all of our revenues are derived from the production of natural gas in the United States. Natural gas and oil revenues were $56.7 million for the year ended December 31, 2008, up 64% from $34.6 million for the year ended December 31, 2007. Average daily production on an equivalent basis was 23.3 MMcfe per day in 2008 compared to 18.1 MMcfe per day in 2007. The increase in revenues was the result of a 29% increase in production, primarily in East Texas from new wells put into production during the year, together with a 28% increase in prices.

During 2008, approximately 56% of our total natural gas production was hedged. The realized effect of hedging on natural gas and oil revenues for the year ended December 31, 2008 was a decrease of $2.4 million in revenues, resulting in a decrease in total natural gas price received from $6.92 per Mcf to $6.63 per Mcf.

 

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Unrealized natural gas hedge income of $6.5 million represents the mark-to-market impact of our derivative contracts outstanding at December 31, 2008. Effective October 1, 2008, we elected to discontinue hedge accounting on all then existing and future derivative contracts pursuant to SFAS No. 133.

Production taxes.     We reported production taxes of $1.3 million for the year ended December 31, 2008, up from $765,000 for the year ended December 31, 2007. The increase was the result of higher revenues in Wyoming due to higher production volumes and prices.

Lease operating expenses.     We reported lease operating expenses of $7.6 million for the year ended December 31, 2008, up from $6.3 million for the year ended December 31, 2007. This increase was due to an increased number of producing wells and increased production. Our lease operating expenses were $0.89 per Mcfe for the year ended December 31, 2008, compared to $0.95 per Mcfe for the comparable period in 2007.

Transportation and treating.     We reported transportation expenses of $2.0 million for the year ended December 31, 2008, up from $1.6 million for the year ended December 31, 2007. This increase reflected greater CBM production volumes in Wyoming subject to transportation and treating. Our Powder River Basin CBM production increased from 5.1 MMcf in 2007 to 5.5 MMcf in 2008.

Depreciation, depletion and amortization.     Depreciation, depletion and amortization was $24.5 million for the year ended December 31, 2008, up from $21.5 million for the year ended December 31, 2007. The increase in DD&A expense was the result of a 29% increase in production, primarily attributable to new East Texas wells drilled during 2008. The DD&A rate for the year ended December 31, 2008 was $2.87 per Mcfe, as compared to $3.24 for the comparable period in 2007.

Impairment of natural gas and oil properties.     Impairment of U.S. natural gas and oil properties was $14.2 million for the year ended December 31, 2008, compared to $28.5 million for the year ended December 31, 2007. The 2008 impairment is the result of net natural gas and oil property costs, as adjusted, exceeding the sum of estimated future net revenues using the weighted average price of $4.56 per Mcf at December 31, 2008, held constant, discounted at 10%, plus unproven properties at historical costs of $118.7 million. The weighted average price in effect at December 31, 2007 was $6.08.

General and administrative.     We reported general and administrative expenses of $14.3 million for the year ended December 31, 2008, down from $16.9 million for the year ended December 31, 2007. This decrease in general and administrative expenses was primarily due to a $3.6 million allowance for doubtful accounts established for certain GeoStar receivables during the year ended December 31, 2007. Excluding the GeoStar allowance, general and administrative expenses for the year ended 2008 increased $1.0 million, primarily due to higher legal and personnel costs partially offset by lower stock-based compensation. Legal costs related to the GeoStar litigation totaled approximately $1.7 million for the year ended December 31, 2008, an increase of $829,000 from the same period in 2007. Non-cash stock-based compensation expense pursuant to the SFAS 123R, which is included in general and administrative expenses, was $3.1 and $3.9 million for the year ended December 31, 2008 and 2007, respectively.

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. There was no litigation settlement expense in 2008. See Note 16—Commitments and Contingencies—Litigation—Arbitration and Litigation with GeoStar Corporation and Affiliates regarding final settlement with GeoStar.

Interest expense.     We reported interest expense of $5.9 million for the year ended December 31, 2008, compared to $14.1 million for the year ended December 31, 2007. The decrease in interest expense reflects $12.2 million and $1.9 million of capitalized interest in 2008 and 2007, respectively, which related to capital expenditures for undeveloped projects in Texas, West Virginia, southwestern Pennsylvania and Australia. Interest expense includes deferred financing cost and debt discount amortization of $2.0 million for 2008, a decrease of $2.2 million from the comparable 2007 period.

 

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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 in 2008.

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 $3.24 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 year ended December 31, 2006. The 2007 impairment is 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 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

 

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certain matters. 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, 2007, 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 in 2006.

Liquidity and Capital Resources

Overview.     Our primary sources of liquidity and capital resources are internally generated cash flows from operating activities, availability under our revolving credit facility, and access to capital markets, to the extent available. The capital markets, as they relate to us, have been adversely impacted by the current financial crisis, concerns about overall deflation and its effect on commodity prices, the possibility of a deepening world recession that may extend for a long period into the future, a lack of liquidity in the banking system and the unavailability and cost of credit. We continually evaluate our capital needs and compare them to our capital resources and ability to raise funds in the financial markets. We adjust capital expenditures in response to changes in natural gas and oil prices, drilling results, and cash flow.

Our consolidated financial statements included in this report have been prepared on the basis of accounting principles applicable to a going concern, which contemplate the realization of assets and satisfaction of liabilities in the normal course of business. For the year ended December 31, 2008, we reported cash flow from operating activities of $40.0 million, net cash utilized in investing activities of $138.2 million, including capital expenditures on natural gas and oil properties of $130.5 million, and net cash provided by financing activities of $18.5 million. As a result of these activities, we utilized $79.7 million of our beginning of the year cash and cash equivalents, resulting in a December 31, 2008 balance of cash and cash equivalents of $6.2 million.

At December 31, 2008, we had a net working capital deficit of approximately $157.2 million, with $151.7 million classified as current portion of long-term debt of which $52.1 million is scheduled to mature in 2009. Included in our current portion of long-term debt are $3.2 million of subordinated notes maturing between April 2009 and September 2009, $18.9 million of debt incurred under our revolving credit facility, $30.0 million of convertible subordinated debentures maturing November 20, 2009 and $99.6 million of 12¾% senior secured notes maturing December 1, 2012. Our revolving credit facility matures on October 15, 2009, unless we automatically extend its maturity to December 1, 2010 by repaying our convertible subordinated debentures or by arranging for repayment of the convertible subordinated debentures on or prior to their maturity in a manner acceptable to the revolving credit facility lenders. In addition, we may have to seek waivers of financial and other covenants in our loan agreements during 2009. If such waivers are needed and not obtained, the failure to obtain such waivers or to make payments on debt when due could result in defaults and as a result of cross default provisions in our various agreements, could result in the acceleration of maturity of all of our debt, including our term loan and 12¾% senior secured notes. It is likely that repaying our debt that is due 2009 will require an inflow of cash from sales of assets, entering into joint ventures or from existing or other credit sources, which may not be available. As described below, our loan agreements may prohibit or significantly restrict our ability to issue new debt or use proceeds from an asset sale for the repayment of our convertible subordinated debentures due in November 2009. These matters raise substantial doubt about our ability to continue as a going concern.

 

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Future capital and other expenditure requirements.     In light of the current events in the financial and commodity markets and the upcoming maturities of a significant amount of our indebtedness, we have decreased our projected 2009 capital activity by $62.5 million from 2008 actual expenditures. Capital expenditures for 2009 are projected to be $71.2 million, consisting of $19.1 million in East Texas, $4.9 million in the Marcellus Shale, $24.3 million in New South Wales, $2.8 million in the Powder River Basin and other capital costs, and an additional $20.1 million for capitalized interest cost. To supplement our cash flow and help fund our 2009 capital budget, we are seeking joint venture partners for the development of our properties, with immediate emphasis on securing a partner in our Marcellus Shale acreage, as well as the possibility of other selected property sales. If we are not successful in raising the additional capital required for our current plan, we may further reduce our drilling and development program. As the operator of our East Texas and Marcellus Shale properties, a portion of our 2009 budget can be reduced, postponed or eliminated at our discretion or without substantial penalty under non-consent clauses applicable to joint exploration and development arrangements.

Based on our revised capital plan, our current cash on hand, and internally generated cash flow, we project that over the next twelve months we will need to raise an additional $95.0 million in order to fund our exploration and development activities, working capital needs and meet the $52.1million in scheduled debt maturities in 2009. The funding of this capital short fall will focus on securing a partner for the joint venture development of the Marcellus Shale, the issuance of additional debt or equity, if possible at acceptable terms, or the sale of other assets located in East Texas and other properties. At current market prices and under current market conditions, it is unlikely that we would seek to issue additional common equity in any public offering; although, we may consider a stock rights offering to existing shareholders or the issuance of warrants or convertible securities to provide funding. The issuance of new common equity may be undertaken if other forms of capital prove to be unavailable due to continued unfavorable credit market conditions.

Commodity prices .    Our cash flow and ability to raise capital are highly dependent upon the price of natural gas. Material decreases in natural gas prices during recent months have significantly and adversely affected our ability to fund our 2009 capital program, our ability to raise additional capital, and our ability to repay outstanding debt at its scheduled maturities in 2009. In order to reduce our exposure to fluctuations in the price of natural gas, we entered into various costless collar, puts and other hedging transactions with counterparties in 2008 and early 2009. Based on our current hedge position, volumes currently hedged represent approximately 67% of our 2009 U.S. projected production. All of our hedges expire in December 2009. A covenant in our revolving credit facility agreement restricts us from hedging more than 85% of the projected natural gas production from proved developed reserves.

Additional material decreases in current and projected natural gas prices could impact our ability to fund future activities, further impairing our ability to raise additional capital on acceptable terms and could contribute to the occurrence of a financial covenant default under our revolving credit facility and term loan, resulting in mandatory principal reductions under certain conditions, and cross defaults to our other credit agreements.

Convertible Subordinated Debentures.     In November 2004, we issued $30.0 million aggregate principal amount of convertible senior unsecured subordinated debentures. The convertible subordinated debentures are due November 20, 2009 and bear interest at 9.75% per annum, payable quarterly. The convertible subordinated debentures are convertible by the holders into 6,849,315 common shares at a conversion price of $4.38 per share. The convertible subordinated debentures may be redeemed at any time by us at a redemption price equal to par plus accrued and unpaid interest; provided that, the volume weighted average trading price of our common shares, for at least 20 trading days in any consecutive 30-day period, equals or exceeds $5.69, 130% of the conversion price of $4.38.

Upon the occurrence of a change of control, as defined in the debenture indenture governing the convertible subordinated debentures, we are required to make an offer to purchase all of the convertible subordinated debentures at a price equal to 101% of the principal amount of the convertible subordinated debentures, plus accrued and unpaid interest. If 90% or more of the principal amount of all convertible subordinated debentures

 

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outstanding on the date we provide notice of a change of control to the convertible subordinated debentures trustee have been tendered for purchase pursuant to the change of control offer, we have the right to redeem the remaining outstanding convertible subordinated debentures on the same date and at the same price.

Subordinated Unsecured Notes Payable .    During 2004, we issued an aggregate $3.25 million of subordinated unsecured notes maturing between April and September 2009. The subordinated unsecured notes bear interest at 10% per annum and are callable by us at 101% of the principal amount of the subordinated unsecured notes. In connection with the issuance of the subordinated unsecured notes the holders were issued 232,521 warrants exercisable at prices ranging from $2.76 to $3.03 per share expiring at varying dates between April and September 2009.

12  3 / 4 % senior secured notes.     On November 29, 2007, our wholly-owned subsidiary, Gastar Exploration USA, Inc. (“Gastar USA”), sold $100.0 million aggregate principal amount of 12  3 / 4 % senior secured notes at an issue price of 99.50%. The 12  3 / 4 % senior secured notes contain certain covenants that among other things limit our 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.

On February 16, 2009, Gastar USA and each of the guarantors of the 12  3 / 4 % senior secured notes entered into a supplemental indenture with the trustee to amend and modify the November 2007 indenture to enable Gastar USA to enter into a $25.0 million first lien secured term loan dated February 16, 2009 with the term loan lender . Among other modifications to covenants contained in the indenture, the supplemental indenture provides that in the event we or any of our subsidiaries sells assets in East Texas, we and Gastar USA must first use the net proceeds from such sale to repay any debt outstanding under the our revolving credit facility and repay amounts outstanding under the term loan. On or before June 1, 2011, any remaining net proceeds must be used for the pro rata redemption of the 12  3 / 4 % senior secured notes at a purchase price equal to 106.375% of principal amount of the notes, plus accrued and unpaid interest, if any, with such asset sale redemption prices decreasing to 103.188% and 100.00% of the principal amount of the 12  3 / 4 % senior secured notes in 2011 and 2012, respectively. Net proceeds from non-East Texas asset sales may be reinvested during the first 360 days from the closing date for the development of any geologic basins in which we or our subsidiaries owned properties as of January 1, 2009, with any uninvested net proceeds after 360 days from the closing date to be used for the repayment of amounts outstanding under the revolving credit facility, the term loan, and the redemption of 12  3 / 4 % senior secured notes in accordance with the terms governing the use of proceeds from asset sales of East Texas properties.

Revolving Credit Facility .    In November 2007, concurrent with the closing of the 12  3 / 4 % senior secured notes, Gastar USA entered into a revolving credit facility, which at December 31, 2008 provided for a first priority lien borrowing base of $19.4 million. At December 31, 2008, there was $18.9 million outstanding under the revolving credit facility and a letter of credit of $100,000 to support our hedging activity. As of March 1, 2009, there was $16.9 million outstanding under the revolving credit facility and a letter of credit of $100,000 to support our hedging activity. Beginning April 1, 2009, the revolving credit facility borrowing base will be reduced by $1.0 million on the first day of each month. Under certain conditions regarding repayment of our outstanding $30.0 million convertible subordinated debentures, the $1.0 million monthly commitment reductions will be suspended for 60 days. If at the expiration of the 60-day period conditions regarding repayment have not closed, the $1.0 million monthly commitment reductions to our credit facility borrowing base will resume. Under the revolving credit facility, we are subject to certain financial covenants, including current ratio requirements.

At December 31, 2008, Gastar USA was not in compliance with a current ratio covenant. On February 16, 2009, we, Gastar USA, certain of our subsidiaries and the revolving credit facility lender as Administrative Agent and Letter of Credit Issuer entered into the Waiver and Second Amendment to Credit Agreement (the “Second Amendment”) to provide for the waiver of a breach of the current ratio covenant under the revolving credit facility and the additional incurrence of first lien secured debt under the term loan. The Second Amendment provides for a waiver of any past or present breach of the current ratio covenant of the revolving credit facility which requires us to

 

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maintain a ratio of current assets to current liabilities of 1.0 to 1.0, as adjusted, which waiver is effective until March 31, 2009. The Second Amendment also provides for an automatic extension of the October 15, 2009 maturity date of the revolving credit facility to December 1, 2010 if we have demonstrated to the Administrative Agent our ability to repay or refinance all of its $30.0 million convertible subordinated debentures due November 29, 2009. The Second Amendment also includes changes to certain affirmative and negative covenants and defined terms in order to conform such covenants to corresponding covenants contained in the term loan.

On March 12, 2009, we, Gastar USA, certain of our subsidiaries and the revolving credit facility lender as Administrative Agent entered into the Waiver under Credit Agreement (the “Third Amendment”) to provide for the waiver of a breach of the current ratio test under the revolving credit facility. The waiver covers the current breach and any future breach of the current ratio covenant as determined as of the end of any quarter of our fiscal year ending December 31, 2009. The Third Amendment also provides for the waiver of a breach of a covenant under the revolving credit facility resulting from our auditors’ issuance of a going concern statement in its report on our 2008 consolidated financial statements.

Term Loan .    Concurrent with the execution of the supplemental indenture, we and Gastar USA entered into a $25.0 million term loan with the term loan lender. On February 17, 2009, Gastar USA drew $25.0 million under the term loan, with proceeds from such incurrence to fund current and future capital commitments and operating costs. Borrowings bear interest at a fixed rate of 20% per annum. The term loan contains various customary covenants, including restrictions on liens, restrictions on incurring other indebtedness without the lender’s consent, restrictions on dividends and other restricted payments, and maintenance of various ratios. The term loan matures on February 15, 2012. Amounts outstanding under the term loan may be prepaid prior to maturity, with a prepayment premium of 10% if repaid prior to December 31, 2009, and a prepayment premium of 5% if repaid between January 1, 2010 through December 31, 2010. Upon a change of control (as defined in the term loan), all amounts outstanding under the term loan will be immediately due and payable.

On March 13, 2009, concurrent with the execution of the Third Amendment, we and Gastar USA entered into the Waiver under Term Loan to provide for a waiver of a breach of a current ratio test under the term loan. The current ratio covenant under the term loan is similar to the covenant in the revolving credit facility. The waiver covers the current breach and any future breach of the current ratio covenant as determined as of the end of any quarter of our fiscal year ending December 31, 2009.

Future waivers .    We continue to be at a substantial risk of a future violation of one or more of the financial covenants contained in our revolving credit facility, term loan and 12  3 / 4 % senior secured notes indenture during 2009. If such a breach occurs and the breached financial covenant provides for an applicable cure period, we expect to seek such a waiver from the applicable lender. If we are unable to cure such violations or obtain such waivers within any applicable cure periods, such violations will constitute an event of default under the revolving credit facility, term loan or indenture, and our lenders could cancel their commitment to lend, accelerate the due dates for the payments of all outstanding indebtedness and exercise their remedies as secured creditors with respect to the collateral securing the revolving credit facility, the term loan and the 12  3 / 4 % senior secured notes. To the extent any waiver is requested, no assurance can be provided that such waiver will be granted or that such waiver will be granted on reasonable terms.

Off Balance Sheet Arrangements

As of December 31, 2008, we had no off balance sheet arrangements. We have no plans to enter into any off balance sheet arrangements in the foreseeable future.

 

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Contractual Obligations

The following table summarizes our future contractual obligations under these arrangements as of December 31, 2008:

 

     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)

   $ 152,125    $ 52,125    $ —      $ 100,000    $ —  

Interest on long-term debt

     53,560      16,180      25,687      11,693      —  

Office lease (2)

     444      264      180      —        —  

Drilling contract (3)

     5,759      5,759      —        —        —  

Operating leases and other (4)

     15      8      7      —        —  
                                  

Total

   $ 211,903    $ 74,336    $ 25,874    $ 111,693    $ —  
                                  

 

(1)

These amounts represent the principal balances that will become due on our revolving credit facility, 12  3 / 4 % senior secured notes, subordinated unsecured notes payable and convertible subordinated debentures.

 

(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 items of office equipment.

We maintain a reserve for cost associated with the retirement of tangible long-lived assets. At December 31, 2008, our reserve for these obligations totaled $5.1 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.

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. At December 31, 2008, the remaining payment due totaled $5.8 million. Under our current capital plans, we anticipate terminating the agreement in late April or early May 2009, which we anticipate will result in a termination cost of approximately $3.0 million.

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 were 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,

 

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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.

New Accounting Pronouncements

Disclosures about Derivative Instruments and Hedging Activities.     In March 2008, the Financial Accounting Standards Board (“FASB”) issued Statements of Financial Accounting Standards (“SFAS”) SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”). SFAS No. 161 requires entities that utilize derivative instruments to provide qualitative disclosures about their objectives and strategies for using such instruments, as well as any details of credit-risk-related contingent features contained within derivatives. SFAS No. 161 also requires entities to disclose additional information about the amounts and location of derivatives located within the financial statements, how the provisions of SFAS No. 133 have been applied, and the impact that hedges have on an entity’s operating results, financial position or cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on the Company’s disclosures.

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 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces SFAS No. 141, “Business Combinations” (“SFAS No. 141”). SFAS 141R retains the fundamental requirements in SFAS No. 141 that the acquisition method of accounting (which SFAS No. 141 called the purchase method) be used for all business combinations. SFAS No. 141R also establishes principles and requirements for how the acquirer: (a) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (b) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (c) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R is effective as of the beginning of an entity’s fiscal year that begins after December 15, 2008. Early adoption is prohibited. The Company is currently evaluating the impact of adopting SFAS No. 141R, which also requires acquisition transaction costs to be expensed as incurred rather than capitalized as a direct cost of the acquisition, as transaction costs are not considered an element of the fair value of the company acquired. The Company’s financial impact depends on the nature and extent of any new business combinations entered into after the effective date of SFAS 141R.

Accounting Standard Fair Value for Financial Assets and Financial Liabilities.     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 allows entities the option to measure eligible financial instruments at fair value as of

 

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specified dates. Such election, which may be applied on an instrument-by-instrument basis, is typically irrevocable once elected. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Company adopted SFAS No. 159 on January 1, 2008, which allows an entity the irrevocable option to elect fair value for the initial and subsequent measurement for certain financial assets and liabilities on a contract-by-contract basis. The Company did not elect fair value as an alternative, as provided under SFAS No. 159 for any of its financial assets and liabilities that are not currently measured at fair value.

Fair Value Measurements.     In September 2006, the FASB issued SFAS 157, “Fair Value Measurements” (“SFAS No. 157”), which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements; however, it does not require any new fair value measurements. The provisions of SFAS No. 157 are effective for the years beginning after November 15, 2007 and interim periods within those years. The FASB has also issued Staff Position FSP FAS No. 157-2 (“FSP FAS 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. In October 2008, the FASB also issued FSP SFAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active”, which clarifies the application of SFAS No. 157 in an inactive market and illustrates how an entity would determine fair value when the market for a financial asset is not active. Effective January 1, 2008, the Company adopted SFAS No. 157 and has chosen to defer the implementation of nonfinancial assets and liabilities in accordance with FSP FAS No. 157-2. The effect of adoption in January 1, 2008 was immaterial to the Company’s financial position. The adoption of FSP FAS No. 157-2 is not expected to have a material impact on the Company’s results of operations, cash flows or financial positions. See Note 9 for additional information regarding the adoption of SFAS No. 157.

The Hierarchy of Generally Accepted Accounting Principles.     In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”) . SFAS No.162 identifies the sources for accounting principles and the framework for selecting the principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States. This Statement became effective in November 2008.

Modernization of Oil and Gas Reporting.     In January 2009, the Securities and Exchange Commission issued revisions to the oil and gas reporting disclosures, “Modernization of Oil and Gas Reporting; Final Rule” (“the Final Rule”). In addition to changing the definition and disclosure requirements for oil and gas reserves, the Final Rule changes the requirements for determining quantities of oil and gas reserves. The Final Rule also changes certain accounting requirements under the full cost method of accounting for oil and gas activities. The amendments are designed to modernize the requirements for the determination of oil and gas reserves, aligning them with current practices and updating them for changes in technology. The Final Rule is effective for annual reports on Form10-K for fiscal years ending on or after December 31, 2009. The Company has not yet determined the impact, if any, on the financial statements.

 

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, 2008, a 10% change in the prices received for natural gas production would have had an approximate $5.9 million impact on our revenues prior to hedge transactions to mitigate our commodity pricing risk. See Note 8—Commodity Hedging Contracts to our consolidated financial statements, beginning on page F-1, for additional information on our hedging activities.

 

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Interest Rate Risk

The carrying value of our debt approximates fair value. At December 31, 2008, we had approximately $152.1 million in principal amount of long-term debt, $133.25 million of which was at a fixed interest rate and $18.9 million was tied to LIBOR. A 10% fluctuation in the LIBOR rates would have had a $72,000 impact on annual interest expense.

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 2008, our Australian activities consisted of capital expenditures totaling approximately $8.8 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, 2008, 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

 

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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, 2008 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; (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, 2008 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 16, 2009     March 16, 2009

Changes in Internal Control over Financial Reporting

During the fourth quarter of 2008, 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, 2008, 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, 2008, 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, 2008 and 2007 and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008 and our report dated March 13, 2009 expressed an unqualified opinion thereon.

/s/ BDO Seidman, LLP

Dallas, Texas

March 13, 2009

 

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Index to Financial Statements
Item 9B. Other Information

None.

 

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Index to Financial Statements

PART III

 

Item 10. Directors and Executive Officers and Corporate Governance

The information regarding directors, executive officers, promoters and control persons required under Item 10 of Form 10-K will be contained in our Definitive Proxy Statement for our 2009 Annual Meeting of Stockholders (the “Proxy Statement”) under the headings “Information about Directors, Director Nominees and Executive Officers”, “Section 16(b) Beneficial Ownership Reporting Compliance”, “Corporate Governance—Code of Ethics”, “Corporate Governance—Nomination of Directors”, and “Committee Information—Audit Committee” and is incorporated herein by reference. The Proxy Statement will be filed with the Securities and Exchange Commission pursuant to Regulation 14A of the Exchange Act, as amended, not later than 120 days after December 31, 2008.

 

Item 11. Executive Compensation

The information required under Item 11 of Form 10-K will be contained in the Proxy Statement under the heading “Executive Compensation” and is incorporated herein by reference.

 

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

The information required under Item 12 of Form 10-K will be contained in the Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.

 

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

The information required under Item 13 of Form 10-K will be contained in the Proxy Statement under the heading “Committee Information” and is incorporated herein by reference.

 

Item 14. Principal Accountant Fees and Services

The information required under Item 14 of Form 10-K will be contained in the Proxy Statement under the heading “Independent Accountant, Fees and Policies” and is incorporated herein by reference.

 

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Index to Financial Statements

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.

(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 Exhibit 3.1 the Company’s Amendment No. 1 to Registration Statement on Form S-1/A filed October 13, 2005, Registration No. 333-127498).

3(ii)

   Bylaws of Gastar Exploration Ltd. approved 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 for the 9.75% Convertible Senior Unsecured Subordinated Debenture (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 West wind 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

   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).

4.5

   Form of 10% subordinated notes issued between April 2004 and September 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).

4.6

   Form of warrant to purchase common shares of Gastar Exploration Ltd issued between April 2004 and September 2004 in connection with the sale of 10% subordinated notes (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).

4.7

   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).

 

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Index to Financial Statements

Exhibit
Number

  

Description

  4.8  

   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).

  4.9  

   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).

  4.10

   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 Exhibit 4.1 of the Company’s Current Report on Form 8-K dated December 4, 2007).

  4.11

   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 (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K dated December 4, 2007).

  4.12

   Warrant dated June 11, 2008, entitling GeoStar Corporation to acquire, subject to adjustments, 10,000,000 Gastar Exploration Ltd. common shares (incorporated by reference to Exhibit 4.1 of the Company’s Current Report of Form 8-K dated June 13, 2008).

  4.1  

   Supplemental Indenture dated as of February 16, 2009, related to the 12  3 / 4 % Senior Secured Notes due 2012, 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. 2007 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated February 20, 2009).

  4.2  

   Term Loan dated as of February 16, 2009 among Gastar Exploration USA, Inc., Gastar Exploration Ltd., certain subsidiaries of Gastar Exploration Ltd., Wayzata Investment Partners LLC, as Administrative Agent and the lenders party thereto (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K dated February 20, 2009).

  4.3  

   Amended and Restated Intercreditor Agreement dated February 16, 2009, 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 (incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K dated February 20, 2009).

  4.4  

   Waiver and Second Amendment to Credit Agreement, dated February 16, 2009, among Gastar Exploration USA, Inc., the Guarantors party thereto and Amegy Bank National Association as Administrative Agent and Letter of Credit Issuer (incorporated by reference to Exhibit 4.4 of the Company’s Current Report on Form 8-K dated February 20, 2009).

10.1*

   The Gastar Exploration Ltd. 2002 Stock Option Plan, dated July 5, 2002 as amended February 14, 2004 (incorporated by reference to Exhibit 10.1 of the Company’s Registration Statement on Form S-1, filed on August 12, 2005. Registration No. 333-127498).

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).

 

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Index to Financial Statements

Exhibit
Number

  

Description

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  

   Form of Subscription Agreement for United States 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).

10.5  

   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).

10.6  

   Form of Subscription Agreement for United States 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).

10.7  

   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).

10.8  

   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).

10.9  

   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).

10.10

   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).

10.11

   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).

10.12

   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).

10.13

   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).

 

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Index to Financial Statements

Exhibit
Number

  

Description

10.14  

   Promissory Note for $15.0 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).

10.15*

   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).

10.16*

   Gastar Exploration Ltd. 2006 Long-Term Stock Incentive Plan approved June 1, 2006 (incorporated herein by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006. File No. 001-32714).

10.17  

   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.)

10.18*

   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).

10.19*

   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).

10.20  

   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).

10.21  

   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 10.2 of the Company’s Current Report on Form 8-K dated May 15, 2007. File No. 001-32714).

10.22  

   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 10.3 of the Company’s Current Report on Form 8-K dated May 15, 2007. File No. 001-32714).

10.23*

   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).

10.24  

   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 Exhibit 4.3 of the Company’s Current Report on Form 8-K dated November 13, 2007).

10.25  

   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 Exhibit 4.4 of the Company’s Current Report on Form 8-K dated December 4, 2007).

 

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Index to Financial Statements

Exhibit
Number

  

Description

10.26*

   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 (incorporated herein by reference to Exhibit 10.18 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007. File No. 001-32714).

10.27  

   Waiver and First Amendment to Credit Agreement among Gastar Exploration USA, Inc., the Guarantors Signatory hereto, the Lenders Signatory hereto and Amegy Bank National Association, as Administrative Agent executed June 6, 2008 and effective as of April 1, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report of Form 8-K dated June 11, 2008).

10.28  

   Settlement Agreement and Comprehensive General Release dated June 11, 2008 for the resolution of disputes between GeoStar Corporation and Gastar Exploration Ltd. (incorporated by reference to Exhibit 10.1 of the Company’s Current Report of Form 8-K dated June 13, 2008).

10.29*

   First Amendment to Employment Agreement entered into by and between Gastar Exploration, Ltd, Gastar Exploration USA, Inc., f/k/a First Sourcenergy Wyoming, Inc., and J. Russell Porter as of July 25, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report of Form 8-K dated July 28, 2008).

10.30*

   First Amendment to Employment Agreement entered into by and between Gastar Exploration, Ltd, Gastar Exploration USA, Inc., f/k/a First Sourcenergy Wyoming, Inc., and Michael A. Gerlich as of July 25, 2008 (incorporated by reference to Exhibit 10.2 of the Company’s Current Report of Form 8-K dated July 28, 2008).

10.31†

   Waiver under Credit Agreement among Gastar Exploration USA, Inc., the Guarantors Signatory thereto the Lenders Signatory Hereto and Amegy Bank National Association, as Administrative Agent, effective March 12, 2009.

10.32†

   Waiver under Credit Agreement Among Gastar Exploration USA, Inc., Gastar Exploration Ltd., the Lenders Signatory Hereto and Wayzata Investment Partners LLC, as Administrative Agent, effective March 13, 2009.

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 16, 2009

/s/    M ICHAEL A. G ERLICH        

Michael A. Gerlich

   Vice President and Chief Financial Officer (principal accounting officer)   March 16, 2009

/s/    A BBY F. B ADWI        

Abby Badwi

   Director   March 16, 2009

/s/    R OBERT D. P ENNER        

Robert D. Penner

   Director   March 16, 2009

/s/    J OHN M. S ELSER S R .        

John M. Selser Sr.

   Director   March 16, 2009

 

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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, 2008 and 2007

   F-3

Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006

   F-4

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2008, 2007 and 2006

   F-5

Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006

   F-6

Notes to Consolidated Financial Statements

   F-7

 

F-1


Table of Contents
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, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material 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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

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, 2008, 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 13, 2009 expressed an unqualified opinion thereon.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the consolidated financial statements, the Company’s need to refinance or raise capital to retire debt maturing in 2009 raises substantial doubt about its ability to continue as a going concern. Management’s plans concerning these matters are described in Note 3. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ BDO Seidman, LLP

Dallas, Texas

March 13, 2009

 

F-2


Table of Contents
Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

     As of December 31,  
     2008     2007  
     (in thousands)  
ASSETS     

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 6,153     $ 85,854  

Accounts receivable, net of allowance for doubtful accounts of $560 and $4,315, respectively

     5,296       4,828  

Commodity derivative contracts

     9,829       —    

Due from related parties

     2,382       904  

Prepaid expenses

     879       1,235  
                

Total current assets

     24,539       92,821  

PROPERTY, PLANT AND EQUIPMENT:

    

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

    

Unproved properties, not being amortized

     141,860       69,844  

Proved properties

     309,103       247,372  
                

Total natural gas and oil properties

     450,963       317,216  

Furniture and equipment

     997       669  
                

Total property, plant and equipment

     451,960       317,885  

Accumulated depreciation, depletion and amortization

     (199,433 )     (160,765 )
                

Total property, plant and equipment, net

     252,527       157,120  

OTHER ASSETS:

    

Restricted cash

     70       1,074  

Deferred charges, net

     6,849       8,334  

Drilling advances

     4,352       2,251  

Other assets

     100       150  
                

Total other assets

     11,371       11,809  
                

TOTAL ASSETS

   $ 288,437     $ 261,750  
                
LIABILITIES AND SHAREHOLDERS’ EQUITY     

CURRENT LIABILITIES:

    

Accounts payable

   $ 14,256     $ 12,001  

Revenue payable

     5,005       6,770  

Accrued interest

     1,505       1,534  

Accrued drilling and operating costs

     2,915       2,810  

Commodity derivative contracts

     1,121       480  

Other accrued liabilities

     3,131       4,831  

Due to related parties

     2,143       979  

Current portion of long-term debt

     151,684       —    
                

Total current liabilities

     181,760       29,405  

LONG-TERM LIABILITIES:

    

Long-term debt

     —         132,685  

Asset retirement obligation

     5,095       4,391  
                

Total long-term liabilities

     5,095       137,076  

COMMITMENTS AND CONTINGENCIES (Note 16)

    

SHAREHOLDERS’ EQUITY:

    

Common stock, no par value, unlimited shares authorized, 209,632,468 and 208,194,570 shares issued and outstanding at December 31, 2008 and 2007, respectively

     249,980       249,980  

Additional paid-in capital

     22,883       14,366  

Accumulated other comprehensive gain (loss)—fair value of commodity hedging

     2,629       (480 )

Accumulated other comprehensive gain (loss)—foreign exchange

     19       (29 )

Accumulated deficit

     (173,929 )     (168,568 )
                

Total shareholders’ equity

     101,582       95,269  
                

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY

   $ 288,437     $ 261,750  
                

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,  
     2008     2007     2006  
     (in thousands, except share and per share data)  

REVENUES:

      

Natural gas and oil revenues

   $ 56,690     $ 34,565     $ 26,765  

Unrealized natural gas hedge

     6,529       —         —    
                        

Total revenues

     63,219       34,565       26,765  

EXPENSES:

      

Production taxes

     1,324       765       1,478  

Lease operating expenses

     7,567       6,284       5,549  

Transportation and treating

     2,002       1,641       1,557  

Depreciation, depletion and amortization

     24,451       21,456       16,332  

Impairment of natural gas and oil properties

     14,217       28,514       56,280  

Accretion of asset retirement obligation

     335       281       234  

Mineral resource properties

     —         (133 )     450  

General and administrative expenses

     14,299       16,906       13,548  

Litigation settlement expense

     —         1,365       2,407  
                        

Total expenses

     64,195       77,079       97,835  
                        

LOSS FROM OPERATIONS

     (976 )     (42,514 )     (71,070 )

OTHER (EXPENSES) INCOME:

      

Interest expense

     (5,853 )     (14,079 )     (15,599 )

Early extinguishment of debt

     —         (15,684 )     —    

Investment income and other

     1,542       3,196       1,836  

Gain on sale of assets

     —         38,536       —    

Foreign transaction gain (loss)

     (74 )     5       (6 )
                        

LOSS BEFORE INCOME TAXES

     (5,361 )     (30,540 )     (84,839 )

Provision for income taxes

     —         —         —    
                        

NET LOSS

   $ (5,361 )   $ (30,540 )   $ (84,839 )
                        

NET LOSS PER SHARE:

      

Basic

   $ (0.03 )   $ (0.15 )   $ (0.50 )
                        

Diluted

   $ (0.03 )   $ (0.15 )   $ (0.50 )
                        

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:

      

Basic and diluted

   $ 207,098,570       202,828,792       170,014,733  
                        

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 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, 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, net of tax

  —       —       —       (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       —    

Stock based compensation

  —       —       3,948     —         —         3,948       —    

Issuance of restricted shares

  1,096,000     —       —       —         —         —         —    

Change in fair value of commodity hedging contract

  —       —       —       (480 )     —         (480 )     (480 )

Foreign currency translation Gain, net of tax

  —       —       —       5       —         5       5  

Net loss

  —       —       —       —         (30,540 )     (30,540 )     (30,540 )
                                               

Total comprehensive loss

              $ (31,015 )
                   

Balance at December 31, 2007

  208,194,570     249,980   $ 14,366     (509 )     (168,568 )     95,269     $ —    

Stock based compensation

  —       —       3,129     —         —         3,129       —    

Issuance of restricted shares

  1,437,898     —       —       —         —         —         —    

Issuance of warrants

  —       —       5,388     —         —         5,388       —    

Commodity hedge contract reclassified to earnings

  —       —       —       2,048       —         2,048       2,048  

Unrealized gain on commodity hedge contracts

  —       —       —       1,061       —         1,061       1,061  

Foreign currency translation Gain, net of tax

  —       —       —       48       —         48       48  

Net loss

  —       —       —       —         (5,361 )     (5,361 )     (5,361 )
                                               

Total comprehensive loss

              $ (2,204 )
                   

Balance at December 31, 2008

  209,632,468   $ 249,980   $ 22,883   $ 2,648     $ (173,929 )   $ 101,582    
                                         

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 CASH FLOWS

 

     For the Years Ended December 31,  
     2008     2007     2006  
     (in thousands)  

CASH FLOWS FROM OPERATING ACTIVITIES:

      

Net loss

   $ (5,361 )   $ (30,540 )   $ (84,839 )

Adjustments to reconcile net loss to net cash provided by (used in) operating activities:

      

Depreciation, depletion and amortization

     24,451       21,456       16,332  

Impairment of natural gas and oil properties

     14,217       28,514       56,280  

Amortization of deferred lease costs

     —         —         345  

Stock based compensation

     3,129       3,948       3,909  

Unrealized natural gas hedge gain

     (6,529 )     —         —    

Amortization of deferred financing costs and debt discount

     1,998       4,235       4,260  

Accretion of asset retirement obligation

     335       281       234  

Gain on sale of assets

     —         (38,536 )     —    

Loss on early extinguishment of debt

     —         12,034       —    

Changes in operating assets and liabilities:

      

Restricted cash for hedging program

     1,000       (1,000 )     —    

Accounts receivable

     (1,946 )     7,395       (6,354 )

Prepaid expenses

     228       134       182  

Accounts payable and accrued liabilities

     8,488       (479 )     8,370  
                        

Net cash provided by (used in) operating activities

     40,010       7,442       (1,281 )
                        

CASH FLOWS FROM INVESTING ACTIVITIES:

      

Development and purchases of natural gas and oil properties

     (130,487 )     (64,841 )     (50,215 )

Proceeds from sale of natural gas and oil properties

     —         66,513       —    

Drilling advances

     (7,485 )     (5,070 )     (14,228 )

Purchase of natural gas and oil properties from related parties

     —         —         (2,116 )

Purchase of furniture and equipment

     (328 )     (69 )     (240 )

Other

     50       —         (150 )
                        

Net cash used in investing activities

     (138,250 )     (3,467 )     (66,949 )
                        

CASH FLOWS FROM FINANCING ACTIVITIES:

      

Proceeds from issuance of 12  3 / 4 % senior secured notes

     —         99,500       —    

Proceeds from revolving credit facility

     18,875       —         —    

Repayment of senior secured notes

     —         (73,000 )     —    

Proceeds from the issuance of common shares, net of share issue costs

     —         23,388       47,915  

Increase in restricted cash

     4       (29 )     (45 )

Deferred financing charges and other

     (340 )     (8,713 )     (51 )
                        

Net cash provided by financing activities

     18,539       41,146       47,819  
                        

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     (79,701 )     45,121       (20,411 )

CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR

     85,854       40,733       61,144  
                        

CASH AND CASH EQUIVALENTS, END OF YEAR

   $ 6,153     $ 85,854     $ 40,733  
                        

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

 

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Table of Contents
Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Description of Business

Gastar Exploration Ltd. (the “Company”) is an independent energy company engaged in the exploration, development and production of natural gas and oil in the United States and Australia. Our principal business activities include the identification, acquisition, and subsequent exploration and development of natural gas and oil properties. Our emphasis is on prospective deep structures identified through seismic and other analytical techniques as well as unconventional natural gas reserves, such as coal bed methane (“CBM”). The Company is pursuing natural gas exploration in the deep Bossier play in the Hilltop area in East Texas and the Marcellus Shale in West Virginia and southwestern Pennsylvania. The Company’s primary CBM properties are in the United States in the Powder River Basin in Wyoming and in the Gunnedah Basin of New South Wales, Australia.

2. Summary of Significant Accounting Policies

The consolidated financial statements of the Company are stated in United States (“U.S.”) dollars unless otherwise noted and have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved natural gas and oil reserve quantities and the related present value of estimated future net cash flows (see “Supplemental Oil and Gas Disclosures”).

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and the consolidated accounts of all its subsidiaries. The entities included in these consolidated accounts are all wholly owned and are Gastar Exploration USA, Inc. (“Gastar USA”), Gastar Exploration Texas, Inc., Gastar Exploration Texas LP, Gastar Exploration Texas LLC, Gastar Exploration New South Wales, Inc. (“Gastar New South Wales”), Gastar Exploration Victoria, Inc. (collectively, “Guarantors”) and Gastar Power Pty Ltd. (“Gastar Power”). All significant intercompany accounts and transactions have been eliminated in consolidation.

Foreign Currency Translation and Exchange

The majority of the Company’s operations are conducted by its U.S. subsidiaries in U.S. dollars. The operations outside of the U.S. are primarily natural gas and oil property development in Australia, whose functional currency is Australian dollars. Our Australian properties represent CBM wells that are in the exploration or pre-production stage. Although we have exploration and development operations in Australia, we currently have no commercial production operations there. Limited operations are conducted by Gastar Exploration Ltd. (“Parent”), whose functional currency is Canadian dollars. Foreign operations are translated using rates in effect at the period end for the balance sheet, while the income statement is translated at the average rates prevailing during the period. Adjustments resulting from financial statement translations are included in cumulative translation adjustments in Accumulated Other Comprehensive Loss and as a component of consolidated statement of shareholders’ equity.

Foreign currency balances and non-monetary assets and liabilities are translated at the rates of exchange on the particular transaction date. Monetary assets and liabilities denominated in foreign currencies that remain outstanding at the balance sheet date are translated at period end exchange rates with resulting gains (losses) being recognized in the period. The accounts of all active U.S. subsidiaries are maintained in U.S. dollars. The accounts of Gastar New South Wales and Gastar Power are maintained in Australian dollars. Translation gains and losses recorded on investments in subsidiaries that are of a permanent nature are not tax effected.

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Cash and Cash Equivalents

Cash and cash equivalents, which includes short-term investments such as money market deposits or highly liquid debt instruments with a maturity of three months or less when purchased, amounted to $6.2 million and $85.9 million as of December 31, 2008 and 2007, respectively. The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant risk of loss.

Accounts Receivable

Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is determined based on a review of the Company’s receivables. Receivable accounts are charged off when collection efforts have failed and the account is deemed uncollectible.

A summary of the activity related to the allowance for doubtful accounts is as follows:

 

     For the Years
Ended December 31,
 
     2008     2007     2006  
     (in thousands)  

Allowance for doubtful accounts, beginning of year

   $ 4,315     $ 626     $ 721  

Expense

     —         3,697       —    

Reductions

     (3,755 )     (8 )     (95 )
                        

Allowance for doubtful accounts, end of year

   $ 560     $ 4,315     $ 626  
                        

Deferred Financing Costs and Debt Discount

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

Debt discount is amortized over the term of the related debt utilizing the effective interest method.

The following table indicates deferred charges and related accumulated amortization as of the dates indicated:

 

     As of December 31,  
     2008     2007  
     (in thousands)  

Deferred charges

   $ 14,552     $ 14,164  

Accumulated amortization

     (7,703 )     (5,830 )
                

Deferred charges, net

   $ 6,849     $ 8,334  
                

Natural Gas and Oil Properties

The Company follows 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. The Company’s 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.

 

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Table of Contents
Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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.

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 is added to costs subject to depletion calculations.

In applying the full cost method, the Company performs 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.

Capitalized Interest

The Company capitalizes interest based on the cost of major development projects, which are excluded from current depreciation, depletion and amortization calculation. Capitalized interest costs were approximately $12.2 million and $1.9 million for 2008 and 2007, respectively. The Company reported no capitalized interest for 2006.

Furniture and Equipment

Furniture and equipment are recorded at historical cost and are depreciated over their estimated useful lives, which ranges from three to seven years on a straight-line basis.

Fair Value of Financial Instruments

The estimated fair values for financial instruments under statement of Financial Accounting Standards (“SFAS”) No. 107, Disclosures about Fair Value of Financial Instruments , are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, marketable securities, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s Revolving Credit Facility approximates carrying value because the facility’s interest rate approximates current market rates. During 2007, the carrying amount of all of the Company’s debt instruments approximated estimated fair value. The following table presents the estimated fair values of the Company’s fixed interest rate debt instruments as of December 31, 2008:

 

     Carrying
Amount
   Estimated
Fair Value
     (in thousands)

12  3 / 4 senior secured notes

   $ 100,000    $ 79,867

9.75% Convertible subordinated debenture

     30,000      27,884

10.0% Subordinated unsecured notes payable

     3,250      3,144
             

Total

   $ 133,250    $ 110,895
             

 

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Table of Contents
Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The Company accounts for its derivative activities under the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities , as amended, (“SFAS No.133”). This statement establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 8, “Derivative and Hedging Activities” for more details.

Revenue Recognition

The Company records revenues from the sale of natural gas and oil when delivery to the customer has occurred and title has transferred. This recording of revenues occurs when natural gas or oil has been delivered to a pipeline or a tank lifting has occurred. Revenues from natural gas and oil production are recorded using the sales method. Under this method, revenues are recorded based on the Company’s net revenue interest, as delivered. The Company had no material gas imbalances at December 31, 2008 and 2007.

Asset Retirement Obligation

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

Mineral Resource Properties

Mineral resource properties are properties that may hold mineral deposits of rutile (titanium dioxide), zircon (zirconium silicate) and other resource minerals. All exploration and related direct and indirect overhead expenditures for mineral resources are expensed. Capitalized acquisition costs, if any, are written off when the decision to abandon the mineral resource property is made.

Deferred Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as income in the period that includes the enactment date. The Company has established a valuation reserve to offset its net deferred tax asset since, on a more likely than not basis, such benefits are not considered recoverable at this time.

Earnings or Loss per Share

In accordance with the provisions of SFAS No. 128, “Earnings per Share” (“SFAS No. 128”), basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding, excluding unvested restricted common shares, during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding, excluding unvested restricted common shares, plus the incremental effect of the assumed issuance of common shares for all potentially dilutive

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

securities. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options, restricted common shares and warrants and the “as if converted” method for convertible debt.

Stock-Based Compensation

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

Effective January 1, 2003, the Company 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 requires the Company to record stock-based compensation costs for options granted under the Company’s stock option plan in accordance with the fair value method prescribed in SFAS No. 123.

Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123R, using the modified-prospective method. Under that method, stock-based compensation cost 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 No. 123R. Compensation expense is recognized 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.

Joint Venture Operation

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

Industry Segment and Geographic Information

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

Treasury Stock

The Company’s common shares are without par value. Treasury stock purchases are recorded at cost as a reduction to common stock. Common shares are cancelled upon repurchase.

Hedging Program

The Company accounts for derivatives and hedging activities in accordance with SFAS No. 133, which requires entities to recognize all derivative instruments on the balance sheet at their respective fair values. Fair value is assessed, measured and estimated by obtaining forward commodity pricing, credit adjusted risk-free interest rates and, as necessary, estimated volatility factors. The fair values the Company reports in its consolidated financial statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond the Company’s control.

 

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Table of Contents
Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The Company utilizes derivative instruments in the form of natural gas costless collars, index swaps, basis swaps and put options to manage price risk associated with future natural gas production. Prior to October 1, 2008, the Company designated and accounted for its derivatives as cash flow hedges of future production under SFAS No. 133. Accordingly, changes in the fair values of the Company’s cash flow hedges were deferred and recorded in accumulated other comprehensive income, as appropriate, until recognized as natural gas and oil revenues in the Company’s consolidated statements of operations as the hedged production is delivered and affects earnings. For all derivatives previously designated as cash flow hedges, the Company was required to assess the effectiveness of the hedging relationships at inception and at every quarter-end.

Effective October 1, 2008, the Company discontinued hedge accounting on all existing derivative contracts and elected not to designate any additional derivative contracts as cash flow hedges. As a result, any subsequent changes in the fair values of discontinued cash flow hedging instruments or new derivative contracts for future production are recognized in unrealized natural gas hedge within the Company’s consolidated statements of operations. Any gains or losses previously deferred under cash flow hedge accounting will remain in accumulated other comprehensive income until the previously hedged production affects earnings or is no longer probable of occurring. All amounts in other comprehensive income will be recorded in natural gas and oil revenues during 2009. Gains or losses from derivative contracts are included in natural gas and oil revenues in the Company’s consolidated statement of operations as the hedged production is delivered.

Restricted Cash

The Company is required to maintain cash balances that are restricted by provisions of certain banking and other agreements. Restricted cash is invested in short term instruments at market rates; therefore, the carrying value approximates fair value. Such cash is included as Other Assets and is excluded from cash and cash equivalents in the consolidated balance sheets.

Reclassifications

Certain information provided for the prior years have been reclassified to conform to the current year presentation.

New Accounting Pronouncements

Disclosures about Derivative Instruments and Hedging Activities.     In March 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”). SFAS No. 161 requires entities that utilize derivative instruments to provide qualitative disclosures about their objectives and strategies for using such instruments, as well as any details of credit-risk-related contingent features contained within derivatives. SFAS No. 161 also requires entities to disclose additional information about the amounts and location of derivatives located within the financial statements, how the provisions of SFAS No. 133 have been applied, and the impact that hedges have on an entity’s operating results, financial position or cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on the Company’s disclosures.

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

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces SFAS No. 141, “Business Combinations” (“SFAS No. 141”). SFAS 141R retains the fundamental requirements in SFAS No. 141 that the acquisition method of accounting (which SFAS No. 141 called the purchase method) be used for all business combinations. SFAS No. 141R also establishes principles and requirements for how the acquirer: (a) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (b) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (c) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R is effective as of the beginning of an entity’s fiscal year that begins after December 15, 2008. Early adoption is prohibited. The Company is currently evaluating the impact of adopting SFAS No. 141R, which also requires acquisition transaction costs to be expensed as incurred rather than capitalized as a direct cost of the acquisition, as transaction costs are not considered an element of the fair value of the company acquired. The Company’s financial impact depends on the nature and extent of any new business combinations entered into after the effective date of SFAS 141R.

Fair Value Measurements.     In September 2006, the FASB issued SFAS 157, “Fair Value Measurements” (“SFAS No. 157”), which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements; however, it does not require any new fair value measurements. The provisions of SFAS No. 157 are effective for the years beginning after November 15, 2007 and interim periods within those years. The FASB has also issued Staff Position FSP FAS No. 157-2 (“FSP FAS 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. In October 2008, the FASB also issued FSP SFAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active”, which clarifies the application of SFAS No. 157 in an inactive market and illustrates how an entity would determine fair value when the market for a financial asset is not active. Effective January 1, 2008, the Company adopted SFAS No. 157 and has chosen to defer the implementation of nonfinancial assets and liabilities in accordance with FSP FAS No. 157-2. The effect of adoption in January 1, 2008 was immaterial to the Company’s financial position. The adoption of FSP FAS No. 157-2 is not expected to have a material impact on the Company’s results of operations, cash flows or financial positions. See Note 9 for additional information regarding the adoption of SFAS No. 157.

Accounting Standard Fair Value for Financial Assets and Financial Liabilities.     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 allows entities the option to measure eligible financial instruments at fair value as of specified dates. Such election, which may be applied on an instrument-by-instrument basis, is typically irrevocable once elected. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007, and early application is allowed under certain circumstances. The Company adopted SFAS No. 159 on January 1, 2008, which allows an entity the irrevocable option to elect fair value for the initial and subsequent measurement for certain financial assets and liabilities on a contract-by-contract basis. The Company did not elect fair value as an alternative, as provided under SFAS No. 159 for any of its financial assets and liabilities that are not currently measured at fair value.

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The Hierarchy of Generally Accepted Accounting Principles.     In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”) . SFAS No. 162 identifies the sources for accounting principles and the framework for selecting the principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States. This Statement became effective in November 2008.

Modernization of Oil and Gas Reporting.     In January 2009, the Securities and Exchange Commission issued revisions to the oil and gas reporting disclosures, “Modernization of Oil and Gas Reporting; Final Rule” (“the Final Rule”). In addition to changing the definition and disclosure requirements for oil and gas reserves, the Final Rule changes the requirements for determining quantities of oil and gas reserves. The Final Rule also changes certain accounting requirements under the full cost method of accounting for oil and gas activities. The amendments are designed to modernize the requirements for the determination of oil and gas reserves, aligning them with current practices and updating them for changes in technology. The Final Rule is effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. The Company has not yet determined the impact, if any, on the financial statements.

3. Going Concern, Liquidity and Capital Resources

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. As of December 31, 2008, the Company classified $151.7 million as current portion of long-term debt, of which $52.1 million is scheduled to mature during 2009. The current portion of this long-term debt actually maturing in 2009 is comprised of $3.2 million of Subordinated Unsecured Notes Payable maturing between April and September 2009, $18.9 million of our Revolving Credit Facility due October 15, 2009 and $30.0 million of Convertible Subordinated Debentures due November 20, 2009. Amounts due under the Revolving Credit Facility are subject to an automatic extension of maturity to December 1, 2010 if the Company demonstrates to the administrative agent its ability to repay or refinance all of the Convertible Subordinated Debentures. Due to the lack of currently identifiable cash resources to repay indebtedness maturing in 2009 and the potential for acceleration of maturity as a result of cross default provisions, the 12¾% Senior Secured Notes are included in current maturities although this indebtedness does not contractually mature until December 1, 2012. Debt maturities, covenants in existing debt agreements restricting the use of asset sale proceeds to retire the Convertible Subordinated Debentures, current commodity price declines and the equity and credit market crisis in the United States, among other factors, indicate that the Company’s ability to raise the cash necessary to retire its maturing indebtedness may be more challenging than in ordinary economic times, which raises substantial doubt about the Company’s ability to continue as a going concern.

Management of the Company is currently pursuing various initiatives in order to generate the liquidity necessary to repay or refinance the obligations that are maturing in 2009, including the sale or partial sale of certain assets, solicitation of joint venture partners to reduce capital costs, general capital cost program reductions, potential issuance of additional debt, possible conversion of certain debt for equity and the issuance of stock rights or other equity offerings. Currently, the Company is (i) in active discussions with several large multi-national energy companies regarding a sale of up to 20% of its interest in PEL 238, a petroleum exploration license in New South Wales, Australia, (ii) actively negotiating terms with private and public exploration and production companies for a joint venture of the Company’s interest in the Marcellus Shale and (iii) in discussions with private equity firms regarding contributions of cash and properties in exchange for equity in the Company. In addition, we have received expressions of interest regarding other potential asset sales in North America. There can be no assurance that the actions undertaken by the Company will result in a capital generating transaction or that any such transaction, if consummated, will generate net cash proceeds sufficient to repay or refinance all of the Company’s current maturities in 2009. The consolidated financial statements do not

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

include any adjustments that might result from the outcome of uncertainty regarding the Company’s ability to raise additional capital, sell assets, or otherwise obtain sufficient funds to meet its current long-term debt obligations in 2009.

4. Property, Plant and Equipment

The amount capitalized as natural gas and oil properties was incurred for the purchase and development of various properties in the states Montana, Pennsylvania, Texas, West Virginia and Wyoming in the United States and in New South Wales and Victoria in Australia. The following schedule represents natural gas and oil property costs by country:

 

     United States     Australia     Total  
     (in thousands)  

From inception to December 31, 2008:

      

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

      

Unproved properties

   $ 118,723     $ 23,137     $ 141,860  

Proved properties

     308,499       604       309,103  
                        

Total natural gas and oil properties

     427,222       23,741       450,963  

Furniture and equipment

     825       172       997  
                        

Total property and equipment

     428,047       23,913       451,960  

Impairment of proved natural gas and oil properties

     (118,423 )     (604 )     (119,027 )

Accumulated depreciation, depletion and amortization

     (80,391 )     (15 )     (80,406 )
                        

Total accumulated depreciation, depletion and amortization

     (198,814 )     (619 )     (199,433 )
                        

Total property and equipment, net

   $ 229,233     $ 23,294     $ 252,527  
                        

From inception to December 31, 2007:

      

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

      

Unproved properties

   $ 46,527     $ 23,317     $ 69,844  

Proved properties

     246,768       604       247,372  
                        

Total natural gas and oil properties

     293,295       23,921       317,216  

Furniture and equipment

     654       15       669  
                        

Total property and equipment

     293,949       23,936       317,885  

Impairment of proved natural gas and oil properties

     (104,205 )     (604 )     (104,809 )

Accumulated depreciation, depletion and amortization

     (55,941 )     (15 )     (55,956 )
                        

Total accumulated depreciation, depletion and amortization

     (160,146 )     (619 )     (160,765 )
                        

Total property and equipment, net

   $ 133,803     $ 23,317     $ 157,120  
                        

At December 31, 2008, unproved properties not being amortized consisted of United States drilling in progress costs of $180,000, U.S. acreage acquisition costs of $108.4 million, Australian unevaluated property costs of $20.4 million and capitalized interest of $12.9 million. As of December 31, 2007, unproved properties not being amortized consisted of U.S. drilling in progress costs of $1.6 million, U.S. acreage acquisition costs of $43.6 million, Australian unevaluated property costs of $22.9 million, and capitalized interest of $1.7 million.

For the years ended December 31, 2008, 2007 and 2006, the results of management’s ceiling test evaluation resulted in an impairment of the U.S. proved properties of $14.2 million, $28.5 million and $56.3 million, respectively. The December 31, 2008 U.S. proved property impairment utilized a weighted average natural gas price of $4.56 per Mcf. Management determined that impairment was not required on the Australian properties at December 31, 2008, 2007 and 2006.

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

In May 2007, the Company sold a portion of its undeveloped natural gas and oil acreage in the Hilltop area of East Texas for approximately $66.5 million in cash, net of transaction costs of approximately $1.2 million, resulting in a gain on sale of $38.5 million. The Company follows the full cost method of accounting, which typically does not allow for gain on sale recognition involving less than 25% of the reserves in a given cost center. Reducing the U.S. full cost pool by the $66.5 million in net sales proceeds would have resulted in an approximate 39% reduction in capitalized cost with no change in proved reserves, thus “significantly altering” the relationship of capitalized costs to proved reserves. The significant reduction in the full cost pool was deemed to be an “out-of-the-ordinary situation”, and the Company determined that gain recognition on the sale of unproven property was the proper accounting treatment.

5. Long-Term Debt

The following shows the Company’s long-term debt at maturity as of the dates indicated:

 

     As of December 31,
     2008    2007
     (in thousands)

Revolving credit facility

   $ 18,875    $ —  

12  3 / 4 % senior secured notes

     100,000      100,000

Convertible subordinated debentures

     30,000      30,000

Subordinated unsecured notes payable

     3,250      3,250
             

Total long-term debt at maturity

     152,125      133,250

Current portion of long-term debt

     151,684      —  

Debt discount costs to be accreted

     441      565
             

Total net carrying value of long-term debt

   $ —      $ 132,685
             

The current portion of long-term debt as of December 31, 2008 is comprised of the following:

 

     Amount
     (in thousands)

Revolving credit facility

   $ 18,875

Convertible subordinated debentures

     30,000

Subordinated unsecured note payable

     3,226
      

Total current maturities—2009

     52,101

12  3 / 4 % senior secured notes due 2012

     99,583
      

Total current portion of long-term debt

   $ 151,684
      

Revolving Credit Facility

On November 29, 2007, Gastar USA, a wholly owned subsidiary of Gastar Exploration Ltd., entered into a revolving credit facility (the “Revolving Credit Facility”) providing for an initial first priority lien maximum borrowing base of $19.4 million at December 31, 2008. At December 31, 2008, the Company had $400,000 of availability under the borrowing base. The borrowing base is redetermined at least semiannually, using the lender’s usual and customary criteria for natural gas and oil reserve valuation. If at any time the outstanding credit extended under the Revolving Credit Facility exceeds the lesser of the aggregate commitments or the applicable borrowing base, the deficiency will be required to be amortized in three monthly installments, and until the deficiency is eliminated, increases in some applicable interest rate margins apply.

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The lender’s commitment under the Revolving Credit Facility is limited to a maximum of $250 million outstanding at any one time, subject to applicable borrowing base limitations. Borrowings under the Revolving Credit Facility bears interest, at Gastar USA’s election, at a prime rate or LIBOR rate, plus an applicable margin. The applicable interest rate margin varies from -0.75% to 0.0% in the case of borrowings based on the prime rate and from 1.5% to 2.25% in the case of borrowings based on the LIBOR rate, depending on the utilization level in relation to the borrowing base. At December 31, 2008, the prime rate and the LIBOR rate were 5.0% and 1.5%, respectively. In addition, an annual commitment fee, ranging from 0.375% to 0.50% depending on borrowing base utilization, is payable on the unused portion of each lender’s commitment.

All outstanding amounts owed under the Revolving Credit Facility become due and payable no later than October 15, 2009, unless extended by the lender, and will be subject to acceleration upon the occurrence of certain usual and customary events of default, including among others:

 

   

Failure to make payments under the Revolving Credit Facility;

 

   

Non-performance of covenants and obligations continuing beyond any applicable grace period; and

 

   

The occurrence of a “change in control” of our Parent.

The Revolving Credit Facility is guaranteed by the Parent and all its current domestic subsidiaries and all future domestic subsidiaries formed during the term of the Revolving Credit Facility. Borrowings and related guarantees under the Revolving Credit Facility are secured by a first priority lien on all domestic natural gas and oil properties currently owned by or later acquired by Gastar USA and its subsidiaries, excluding de minimus value properties as determined by the lender. The facility is secured by a first priority pledge of the stock of each domestic subsidiary, a first priority interest on all accounts receivable, notes receivable, inventory, contract rights, general intangibles and material property of the Issuer and 65% of the stock of each foreign subsidiary of the Issuer.

The Revolving Credit Facility contains various covenants, including among others:

 

   

Restrictions on liens;

 

   

Restrictions on incurring other indebtedness without lender’s consent;

 

   

Restrictions on Company dividends and other restricted payments;

 

   

Maintenance of a minimum consolidated current ratio, as adjusted, of not less than 1.0 to 1.0;

 

   

Maintenance of a maximum total net debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”), on a rolling four quarters basis, as adjusted, of not more than 4.25 to 1.0 for the quarter ended December 31, 2008 and 4.0 to 1.0 for all quarters thereafter;

 

   

Limitation on general and administrative expense, excluding any stock based compensation costs, not to exceed 25% of consolidated revenue less lease operating and production tax expenses, as adjusted, for any quarter; and

 

 

 

Maintenance of cash liquidity equal to the semi-annual interest payment under 12  3 / 4 % Senior Secured Notes (see below), so long as the borrowing based under the Revolving Credit Facility is less than $40.0 million.

Should there occur a change of control of the Parent, then, five days after such occurrence, immediately and without notice, (i) all amounts outstanding under the Revolving Credit Facility shall automatically become immediately due and payable and (ii) the commitments shall immediately cease and terminate unless and until reinstated by the lender in writing. If amounts outstanding under the Revolving Credit Facility become

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

immediately due and payable in accordance with the immediately preceding sentence, the obligation of Gastar USA with respect to any commodity hedge exposure shall be to provide cash as collateral to be held and administered by the lender as collateral agent.

As of December 31, 2008, the Company was not in compliance with the current ratio covenant. On February 16, 2009, a waiver and second amendment to the Revolving Credit Agreement was obtained in conjunction with the Company entering into a new $25.0 million term loan (the “Term Loan”). On March 12, 2009, the Company received a waiver and third amendment to the Revolving Credit Agreement. See Note 18, “Subsequent Events” for information about the waviers and amendments to the Revolving Credit Facility.

12  3 / 4 % Senior Secured Notes due 2012

On November 29, 2007, Gastar USA sold $100.0 million aggregate principal amount of 12  3 / 4 % Senior Secured Notes due December 1, 2012 (“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 were used to repay the then outstanding senior secured notes, with the remaining net proceeds to be used for general corporate purposes. The 12  3 / 4 % Senior Secured Notes mature on December 1, 2012.

Interest is payable, semi-annually on June 1 and December 1, in cash on the principal amount at an annual rate of 12  3 / 4 %. The annual effective interest rate, after amortization of the debt discount and fees paid to establish the 12  3 / 4 % Senior Secured Notes, is 15.0%. The 12  3 / 4 % Senior Secured Notes are fully and unconditionally guaranteed jointly and severally by Gastar USA, the Parent and all of the Parent’s existing and future material domestic subsidiaries. The 12  3 / 4 % Senior Secured Notes and the guarantees rank equal in right of payment with all existing and future senior indebtedness of Gastar USA and the Guarantors and senior in right of payment to any future subordinated indebtedness of Gastar USA and the Guarantors, as applicable. The 12  3 / 4 % Senior Secured Notes and the guarantees are secured by a lien on Gastar USA’s principal domestic oil and gas properties and other assets that secure Gastar USA’s Revolving Credit Facility, subject to certain exceptions. Pursuant to the terms of an intercreditor agreement (the “Intercreditor Agreement”), the lien securing the 12  3 / 4 % Senior Secured Notes is contractually subordinated to (i) the lien that secures the Revolving Credit Facility and (ii) certain hedging obligations of Gastar USA. Consequently, the 12  3 / 4 % Senior Secured Notes and the guarantees are effectively subordinated to Gastar USA’s and the Guarantors’ secured obligations, including the Revolving Credit Facility, to the extent of the value of the assets securing such obligations.

At any time prior to June 1, 2010, Gastar USA may redeem the 12  3 / 4 % Senior Secured Notes, in whole or in part, at a redemption price equal to 100% of the principal amount plus the applicable premium. The applicable premium is the greater of (i) 1.0% of the 12  3 / 4 % Senior Secured Notes being redeemed and (ii) the excess of (A) the present value at such time of (1) redemption price of 12  3 / 4 % Senior Secured Notes as of June 1, 2010 (without regard to accrued and unpaid interest) plus (2) all required interest payments due on 12  3 / 4 % Senior Secured Notes through June 1, 2010, computed using a discount rate equal to the Treasury Rate plus 50 basis points, over (B) the principal amount of 12  3 / 4 % Senior Secured Notes. At any time and from time to time prior to June 1, 2010, Gastar USA may redeem up to 35% of the aggregate principal amount of the 12  3 / 4 % Senior Secured Notes with the net cash proceeds of one or more equity offerings at 112.750% of the aggregate principal amount, plus accrued and unpaid interest. On or after June 1, 2010, Gastar USA may redeem the 12  3 / 4 % Senior Secured Notes during the 12-month periods beginning on June 1 of the years and at a premium as set forth below:

 

Twelve-Month Period Beginning June 1,

   Percentage  

2010

   106.375 %

2011

   103.188 %

2012

   100.000 %

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

If a change of control of Parent, as defined in the indenture governing the 12  3 / 4 % Senior Secured Notes (the “Indenture”), occurs, the holders of 12  3 / 4 % Senior Secured Notes have the right to require Gastar USA to repurchase the 12  3 / 4 % Senior Secured Notes at 101% of principal amount, plus accrued and unpaid interest.

Within 30 days of an asset sale greater than $10.0 million, excluding Wyoming property sales, Gastar USA will offer to use the net proceeds to repurchase that portion of the 12  3 / 4 % Senior Secured Notes at a premium as set forth below:

 

Twelve-Month Period Beginning June 1,

   Percentage  

Prior to June 1, 2011

   106.375 %

June 2, 2011 to June 1, 2012

   103.188 %

After June 1, 2012

   100.000 %

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 Company 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, Gastar USA may incur up to $25.0 million of indebtedness under the Revolving Credit Facility and such additional amounts of 12  3 / 4 % Senior Secured Notes or indebtedness subordinate to the 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. As of December 31, 2008, the Company was in compliance with all debt covenants.

On February 16, 2009, consents to certain amendments and modification to the Indenture of the 12  3 / 4 % Senior Secured Notes were obtained in conjunction with the Company entering into a Term Loan. See Note 18, “Subsequent Events” for information about the amendments and modifications to the 12  3 / 4 % Senior Secured Notes Indenture.

Convertible Subordinated Debentures

In November 2004, the Company issued $30.0 million aggregate principal amount of convertible senior unsecured subordinated debentures (the “Convertible Subordinated Debentures”). The Convertible Subordinated Debentures have a term of five years and are due November 20, 2009 and bear interest at 9.75% per annum, payable quarterly. The Convertible Subordinated Debentures are convertible by the holders into 6,849,315 common shares at a conversion price of $4.38 per share. The Convertible Subordinated Debentures may be redeemed at any time by the Company at a redemption price equal to par plus accrued and unpaid interest; provided that, the volume weighted average trading price of the common shares of the Company, for at least 20 trading days in any consecutive 30-day period, equals or exceeds $5.69, 130% of the conversion price of $4.38.

The Company incurred an estimated $1.9 million of direct financing costs for legal fees and other expenses as deferred charges, which are being amortized over the term of Convertible Subordinated Debentures. The Company also issued 259,740 broker warrants with an exercise price of $3.87 and a fair value of $359,000. There was no beneficial conversion feature associated with the Convertible Subordinated Debentures.

On February 3, 2006, the Company issued 21,948 common shares upon exercise of 21,948 broker warrants at $3.87 per share issued in connection with the sale of the Convertible Subordinated Debentures. The remaining 237,792 broker warrants expired in May 2006.

Upon the occurrence of a change of control, as defined in the debenture indenture governing the Convertible Subordinated Debentures, the Company is required to make an offer to purchase all of the Convertible Subordinated Debentures at a price equal to 101% of the principal amount of the Convertible Subordinated

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Debentures, plus accrued and unpaid interest. If 90% or more of the principal amount of all Convertible Subordinated Debentures outstanding on the date the Company provides notice of a change of control to the Convertible Subordinated Debentures trustee have been tendered for purchase pursuant to the change of control offer, the Company has the right to redeem the remaining outstanding Convertible Subordinated Debentures on the same date and at the same price.

Subordinated Unsecured Notes Payable

The Company’s $3.25 million subordinated unsecured notes mature between April and September 2009, bear interest at 10% per annum and are callable by the Company at 101%. The subscribers were issued 232,521 warrants exercisable at prices ranging from $2.76 to $3.03 expiring at varying dates between April and September 2009. A value of $235,000 was ascribed to the warrants and recorded as a debt discount to be accreted to interest expense using the effective interest method. Cash commissions of $196,000 were incurred, which have been capitalized and are being amortized over the term of the subordinated unsecured notes.

Senior Secured Notes

On June 17, 2005 and September 19, 2005, the Company issued $63.0 million and $10.0 million, respectively, in principal amount of senior secured notes (“Senior Secured Notes”). The Senior Secured Notes were secured by substantially all of the Company’s assets, had interest payable quarterly equal to the sum of the three-month LIBOR rate at the beginning of the current quarter plus 6.0%, and matured five years and one day from the date of issuance. The Senior Secured Notes were redeemable in whole or in part prior to maturity at the Company’s option at any time upon payment of the principal and accrued and unpaid interest plus a premium of 5% until the third anniversary of issuance, 4% from the third anniversary to the fourth anniversary and 3% from the fourth anniversary until the day before maturity. Redemption at the Company’s option was not permitted following the public announcement of certain pending, proposed or intended change of control transactions.

In connection with the Senior Secured Notes issuances, the Company agreed to issue to the note holders, for no additional consideration, common shares in increments valued at CDN$4.5 million with respect to the $63.0 million of Senior Secured Notes and additional common shares in increments valued at CDN$714,286 with respect to the $10.0 million of Senior Secured Notes at closing and on each of the six, twelve and eighteen-month anniversaries of the closing date, valued on a five-day weighted average trading price immediately prior to the date of issuance. The Company initially recorded a liability of $17.0 million related to common shares to be issued and a corresponding amount recorded as a debt discount to be accreted to interest expense using the effective interest method. The Company also incurred an estimated $3.0 million of direct financing costs for legal fees and fees paid to an agent as deferred charges and are amortizing these costs over the term of the Senior Secured Notes. Subsequent to the March 19, 2007 issuance of common shares to the note holders, the Company had no further obligation to issue additional common shares under the senior secured notes.

On November 29, 2007, in connection with the sale of $100.0 million aggregate principal amount of 12  3 / 4 % Senior Secured Notes, the Company repaid in full the $73.0 million of senior secured notes. The Company paid a prepayment penalty of $3.65 million, or 5% of the aggregate principal amount repaid.

Term Loan

On February 16, 2009, concurrent with the execution of the amendments and modifications to the Indenture, Gastar USA and the Company entered into the Term Loan. On March 13, 2009, concurrent with the execution of the Third Amendment to the Revolving Credit Agreement, the Company entered into a waiver under the Term Loan. See Note 18, “Subsequent Events” for information about the Term Loan and related waiver.

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Long-term Debt Maturities

The following table represents the scheduled maturities of the Company’s long-term debt:

 

     Amount
     (in thousands)

2009

   $ 52,125

2010

     —  

2011

     —  

2012

     100,000

2013

     —  
      

Total

   $ 152,125
      

Loss on Early Extinguishment of Debt

On November 29, 2007, as a result of the prepayment prior to maturity of the $73.0 million of senior secured notes, the Company expensed all unamortized deferred financing costs of $2.7 million, $9.3 million debt discount costs being accreted and $3.7 million of early prepayment penalty, resulting in a loss on early debt extinguishment of $15.7 million.

6. Asset Retirement Obligation

The Company accounts for its liabilities associated with site restoration and abandonment of its natural gas and oil properties pursuant to the provisions of SFAS No. 143. A summary of the activity related to the asset retirement obligation is as follows:

 

     For the Years Ended
December 31,
     2008     2007     2006
     (in thousands)

Asset retirement obligation, beginning of year

   $ 4,391     $ 4,218     $ 3,558

Liabilities incurred

     443       642       426

Accretion expense

     335       281       234

Revision in previous estimates and other

     (74 )     (750 )     —  
                      

Asset retirement obligation, end of year

   $ 5,095     $ 4,391     $ 4,218
                      

7. Equity Compensation Plans

Share-Based Compensation Plans

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 ten 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

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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.

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, 2008, stock option grants covering the issuance of 9,648,750 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 the grant is awarded. The vesting period for restricted common stock grants during 2008 was over four years, with one-third vesting on the second, third and fourth anniversaries of the date of grant. As of December 31, 2008, 2,533,898 restricted common shares were the only grants outstanding under the 2006 Gastar Long-Term Stock Incentive Plan.

Determining Fair Value under SFAS No. 123R

In determining fair value for stock option grants pursuant to SFAS No. 123R, the Company utilized the following assumptions:

Valuation and Amortization Method.     The Company estimates the fair value of share-based awards granted using the Black-Scholes-Merton valuation model. The fair value of all awards is expensed using the “graded-vesting method”.

Expected Life.     The expected life of awards granted represents the period of time that stock options are expected to be outstanding. The Company determined the expected life to be 6.25 years, based on historical information, for all stock options issued with a four-year vesting period and ten-year grant expiration. Using historical information, stock options that have been issued with two and three-year vesting periods and have a ten-year expiration have an expected life of 5.75 and 6.0 years, respectively.

Expected Volatility.     Using the Black-Scholes-Merton valuation model, the Company estimates the volatility of its common shares at the beginning of the quarter in which the stock option is granted. The volatility is based on historical movements of our common share price on the American Stock Exchange and the Toronto Stock Exchange over a period that approximates the expected life.

Risk-Free Interest Rate.     The Company utilizes a risk-free interest rate equal to the rate of U.S. Treasury zero-coupon issues as of the date of grant with a term equivalent to the stock option’s expected life.

Expected Dividend Yield.     The Company has not paid any cash dividends on its common shares and does not anticipate paying any cash dividends in the foreseeable future. Consequently, a dividend yield of zero is utilized in the Black-Scholes-Merton valuation model.

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Expected Forfeitures.     The Company utilized a forfeiture rate of 6% for 2008 and 5% for 2007 and 2006 in determining initial compensation expense, based on forfeitures of all unvested stock option as a percentage of all stock option grants calculated at the beginning of the year.

The fair value of each stock option grant is estimated on the date of grant using the Black-Scholes-Merton valuation pricing model. There were no stock option grants in 2008. The table below summarizes the number of stock options granted and the assumptions for the stock options granted for the periods indicated:

 

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

Stock options granted

   828,000     4,790,000  

Expected life (in years)

   6.25     6.5  

Expected volatility

   44.4%-44.7 %   45.7 %

Risk-free interest rate

   4.3%-5.1 %   5.0 %

The weighted average grant date fair value of stock options granted and the intrinsic value of stock options exercised are shown below for the periods indicated. Intrinsic value of stock options is calculated using the difference between the common share price on the date of exercise and the exercise price times the number of stock options exercised. There were no stock options granted or exercised in 2008.

 

     As of December 31,
     2008    2007    2006
     (in thousands)