GASTAR EXPLORATION LTD

FORM 10-K

(Annual Report)

Filed 03/16/09 for the Period Ending 12/31/08

 

Address 1331 LAMAR STREET

SUITE 1080

HOUSTON, TX 77010

Telephone 7137391800

CIK 0001170154

Symbol GST

SIC Code 1311 - Crude Petroleum and Natural Gas

Industry Oil & Gas - Integrated

Sector Energy

Fiscal Year 12/31

 

http://www.edgar-online.com

© Copyright 2009, EDGAR Online, Inc. All Rights Reserved.

Distribution and use of this document restricted under EDGAR Online, Inc. Terms of Use.
Table of Contents 

Index to Financial Statements 

 

UNITED STATES 

SECURITIES AND EXCHANGE COMMISSION 

Washington, D.C. 20549 

FORM 10-K 

 

 

or 

 

 

Commission file number: 001-32714 

GASTAR EXPLORATION LTD. 

(Exact name of registrant as specified in its charter) 

 

(713) 739-1800 

(Registrant’s telephone number, including area code) 

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

 

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  

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  

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  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.  

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  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  

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. 

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

 For the Fiscal Year Ended December 31, 2008 

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

 For the transition period from to 

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) 

 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) 
As of March 12, 2009, there were 209,632,468 common shares outstanding. 

Documents incorporated by reference. None 

 

 
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Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2008 

TABLE OF CONTENTS 

 

 

i 

 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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Index to Financial Statements 

 

ii 

 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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Index to Financial Statements 

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: 

 

 

 

 

 

 

 

 

 

 

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: 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

iii 

 • 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. 

 • 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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Index to Financial Statements 

 

 

 

 

 

 

 

 

 

 

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. 

 

iv 

 • 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. 
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Index to Financial Statements 

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 

 

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. 

 

1 

Item 1. Business 
Table of Contents 

Index to Financial Statements 

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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Index to Financial Statements 

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-NewcastleWollongong 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 

 

3 
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Index to Financial Statements 

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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Index to Financial Statements 

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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Index to Financial Statements 

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 mid2009. 

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 intrastate 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. 

 

15 
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Index to Financial Statements 

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: 

 

 

 

 

 

 

 

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. 

 

16 

 • 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 
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Index to Financial Statements 

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 123⁄4% 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 

 

17 
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Index to Financial Statements 

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: 

 

 

 

 

 

 

 

 

18 

 • 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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Index to Financial Statements 

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: 

 

 

 

 

 

 

 

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 

 

19 

 • 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. 
Table of Contents 

Index to Financial Statements 

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 longterm 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 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. 

 

20 

 

• 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. 
Table of Contents 

Index to Financial Statements 

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: 

 

 

 

 

 

 

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: 

 

 

21 

 • 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. 

 • The amount and timing of actual production; 
Table of Contents 

Index to Financial Statements 

 

 

 

 

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: 

 

 

 

 

 

 

 

 

22 

 • 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. 

 • 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. 
Table of Contents 

Index to Financial Statements 

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 

 

23 
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Index to Financial Statements 

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: 

 

 

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: 

 

 

 

 

 

 

 

24 

 

• 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. 

 • 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; 
Table of Contents 

Index to Financial Statements 

 

 

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

 

 

 

 

 

 

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. 

 

25 

 • Pipeline ruptures or spills; 

 • Natural disasters; and 

 • Releases of toxic natural gas. 

 • 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. 
Table of Contents 

Index to Financial Statements 

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. 

 

26 
Table of Contents 

Index to Financial Statements 

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: 

 

 

 

 

 

 

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, 

 

27 

 • 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. 
Table of Contents 

Index to Financial Statements 

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: 

 

 

 

 

 

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: 

 

 

 

 

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. 

 

28 

 • 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. 

 • Timing and amount of capital expenditures; 

 • The operator’s expertise and financial resources; 

 • Approval of other participants in drilling wells; and 

 • Selection of technology. 
Table of Contents 

Index to Financial Statements 

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 

 

29 
Table of Contents 

Index to Financial Statements 

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. 

 

None. 

 

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

 

 

 

 

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

 

30 

Item 1B. Unresolved Staff Comments 

Item 2. Properties 

 • 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. 
Table of Contents 

Index to Financial Statements 

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. 

 

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. 

 

 

31 

 

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. 

 

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 

 
Table of Contents 

Index to Financial Statements 

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. 

 

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. 

 

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 

 

32 

 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 

 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 

 
Table of Contents 

Index to Financial Statements 

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. 

 

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: 

 

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. 

 

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. 

 

During the three months ended December 31, 2008, no matters were submitted to a vote of security holders. 

 

33 

 Total Proved Reserves as of December 31, 2008 

 Producing 

Nonproducing 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 

 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 

Item 3. Legal Proceedings 

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

Index to Financial Statements 

PART II 

 

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. 

 

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. 

 

34 

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

 

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.
Table of Contents 

Index to Financial Statements 

 

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. 

 

 

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. 

 

35 

Item 6. Selected Financial Data 

 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 
Table of Contents 

Index to Financial Statements 

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: 

 

 

 

 

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. 

 

36 

 • 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. 
Table of Contents 

Index to Financial Statements 

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: 

 

 

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, 

 

37 

 • 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. 
Table of Contents 

Index to Financial Statements 

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. 

 

38 
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Index to Financial Statements 

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-adjustedrisk-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. 

 

39 
Table of Contents 

Index to Financial Statements 

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 modifiedprospective 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 grantdate 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: 

 

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. 

 

40 

 

For the Year 

Ended 

December 31, 2007 

Expected volatility 44.4% – 44.7 % 

Expected life (in years) 6.25 

Expected forfeitures 5.0 % 
Table of Contents 

Index to Financial Statements 

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: 

 

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. 

 

41 

 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. 
Table of Contents 

Index to Financial Statements 

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. 

 

42 
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Index to Financial Statements 

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 

 

43 
Table of Contents 

Index to Financial Statements 

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 123⁄4% 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 123⁄4% 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. 

 

44 
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Index to Financial Statements 

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 

 

45 
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Index to Financial Statements 

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 

 

46 
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Index to Financial Statements 

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. 

 

47 
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Index to Financial Statements 

Contractual Obligations 

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

 

 

 

 

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, 

 

48 

 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. 
Table of Contents 

Index to Financial Statements 

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 

 

49 
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Index to Financial Statements 

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 contractby-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. 

 

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. 

 

50 

Item 7A. Quantitative and Qualitative Disclosure about Market Risk 
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Index to Financial Statements 

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. 

 

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. 

 

Not applicable. 

 

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 

 

51 

Item 8. Financial Statements and Supplementary Data 

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

Item 9A. Controls and Procedures 
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Index to Financial Statements 

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. 

 

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. 

 

52 

/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 
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 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 

 

53 
Table of Contents 

Index to Financial Statements 

None. 

 

54 

Item 9B. Other Information 
Table of Contents 

Index to Financial Statements 

PART III 

 

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. 

 

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. 

 

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. 

 

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. 

 

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. 

 

55 

Item 10. Directors and Executive Officers and Corporate Governance 

Item 11. Executive Compensation 

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

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

Item 14. Principal Accountant Fees and Services 
Table of Contents 

Index to Financial Statements 

PART IV 

 

(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 

 

 

56 

Item 15. Exhibits, Financial Statement Schedules 

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). 
Table of Contents 

Index to Financial Statements 

 

57 

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). 
Table of Contents 

Index to Financial Statements 

 

58 

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 nonproducing 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). 
Table of Contents 

Index to Financial Statements 

 

59 

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). 
Table of Contents 

Index to Financial Statements 

 

 

 

60 

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. 
Table of Contents 

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. 

 

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. 

 

 

61 

GASTAR EXPLORATION LTD. 

/s/ J. R USSELL P ORTER 

J. Russell Porter, 

Chairman, President, 

Chief Executive Officer and Chief Operating 

Officer (principal executive officer) 

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 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS 

 

 

F-1 

 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 
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 

 

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

 

F-3 

 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 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF OPERATIONS 

 

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

 

F-4 

 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 

 

 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY 

 

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

 

F-5 

 Common Stock Additional 

Paid-in 

Capital 

 

Accumulated 

Other 

Comprehensive 

Loss 

 

Accumulated 

Deficit 

 Total 

Shareholders’

Equity 

 

Comprehensive 

 Shares Amount Loss 

 (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 

 

 

 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF CASH FLOWS 

 

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

 

F-6 

 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 

 

 

 

 

 

 
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. 

 

F-7 
Table of Contents 

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: 

 

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: 

 

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. 

 

F-8 

 

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 

 

 

 

 

 

 

 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 

 

 

 

 
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: 

 

 

F-9 

 

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 

 
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 longlived 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 

 

F-10 
Table of Contents 

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. 

 

F-11 
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 

 

F-12 
Table of Contents 

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. 

 

F-13 
Table of Contents 

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 123⁄4% 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 

 

F-14 
Table of Contents 

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: 

 

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. 

 

F-15 

 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 

 

 

 

 

 

 
Table of Contents 

Index to Financial Statements 

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: 

 

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

 

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. 

 

F-16 

 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 

 

 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 

 
Table of Contents 

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: 

 

 

 

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: 

 

 

 

 

 

 

 

 • 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. 

 • 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 

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 

 

F-17 

 

• 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. 
Table of Contents 

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: 

 

 

F-18 

Twelve-Month Period Beginning June 1, Percentage 

2010 106.375 % 

2011 103.188 % 

2012 100.000 % 
Table of Contents 

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: 

 

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-quarterperiod 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 

 

F-19 

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 % 
Table of Contents 

Index to Financial Statements 

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. 

 

F-20 
Table of Contents 

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: 

 

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: 

 

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 

 

F-21 

 Amount 

 (in thousands) 

2009 $ 52,125 

2010 — 

2011 — 

2012 100,000 

2013 — 

 

Total $ 152,125 

 

 

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 

 

 

 

 

 
Table of Contents 

Index to Financial Statements 

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-ScholesMerton 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. 

 

F-22 
Table of Contents 

Index to Financial Statements 

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: 

 

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. 

 

Stock Option Activity 

The following table summarizes the annual changes and option exercise prices for stock options under the Company’s Stock Option Plan 

for the year ended December 31, 2008. 

 

 

F-23 

 

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 % 

 As of December 31, 

 2008 2007 2006 

 (in thousands) 

Weighted average grant date fair value of outstanding stock options $ 1.16 $ 1.11 $ 1.28 

Intrinsic value of stock options exercised (000) $ — $ — $ 2,922 

Fair value of stock option shares vested during year (000) $ 3,233 $ 2,912 $ 2,516 

 

Number of 

Shares Under 

Stock Options 

Weighted 

Average 

Exercise 

Price 

Stock options outstanding as of December 31, 2007 10,173,750 $ 3.19 

Stock options granted — $ — 

Stock options exercised — — 

Stock options cancelled/expired (525,000 ) $ 2.17 

 

Stock options outstanding as of December 31, 2008 9,648,750 $ 2.76 

 

 

 

Stock options exercisable: 

December 31, 2008 7,849,583 $ 2.74 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

The table below summarizes certain information about the stock options for the year ended December 31, 2008. Fair value calculations are 

as of the date of grant. 

 

As of December 31, 2008, there was no aggregate intrinsic value for outstanding stock options, and the remaining weighted average 

contractual life of outstanding stock options was 4.2 years. As of December 31, 2008, there was no aggregate intrinsic value for exercisable 

stock options, and the remaining weighted average contractual life of exercisable stock options was 3.5 years. As of December 31, 2008, the total 

fair value of exercisable stock options was $8.8 million. 

The following table summarizes the range of exercise prices for stock options outstanding and exercisable as of December 31, 2008: 

 

 

F-24 

 

Number of 

Shares Under 

Stock Options 

Weighted 

Average 

Fair Value 

Unvested stock options at the beginning of year 5,045,834 $ 1.22 

Unvested stock options at the end of the year 1,799,167 $ 1.34 

Stock options granted during the year — $ — 

Stock options vested during the year 2,821,667 $ 1.15 

Stock options forfeited during the year — $ — 

 

Number of Shares 

Under Stock Options Exercise 

Expiration Date Outstanding Exercisable Prices (1) 

April 20, 2009 625,000 625,000 $ 3.03 

August 4, 2009 3,553,750 3,553,750 $ 2.79 

April 4, 2010 21,000 15,750 $ 3.52 

June 24, 2010 345,000 211,250 $ 2.86 

June 28, 2010 50,000 37,500 $ 2.78 

September 7, 2010 150,000 112,500 $ 2.66 

September 20, 2010 40,000 30,000 $ 3.27 

October 17, 2015 75,000 56,250 $ 3.68 

January 16, 2016 270,000 135,000 $ 4.10 

April 5, 2016 838,000 419,000 $ 3.93 

May 24, 2016 50,000 25,000 $ 2.66 

July 14, 2016 2,930,000 2,453,333 $ 2.32 

March 30, 2017 200,000 50,000 $ 2.17 

July 3, 2017 300,000 75,000 $ 2.20 

July 7, 2017 200,000 50,000 $ 2.19 

August 30, 2017 1,000 250 $ 1.67 

 

 9,648,750 7,849,583 

 

 

(1) Stock options granted with strike prices denominated in CDN$ have been converted to US$ by multiplying the CDN$ strike price by the 

exchange rate at December 31, 2008. 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

Restricted Share Activities 

The following table summarizes the changes and grant date prices for restricted common share grants for the year ended December 31, 

2008: 

 

The following table summarizes the range of grant dates (expiration dates) and grant date prices for restricted common shares outstanding 

and unvested as of December 31, 2008: 

 

As of December 31, 2008, the remaining weighted average contractual life of unvested restricted common shares was 3.0 years. The 

following table shows the total value and weighted average fair value per share of restricted common shares outstanding for the periods 

indicated: 

 

Stock-Based Compensation Expense 

For the years ended December 31, 2008, 2007 and 2006, the Company recorded stock-based compensation expense for stock options and 

restricted common shares granted using the fair-value method of $3.1 million, $3.9 million and $3.9 million, respectively. All stock based 

compensation costs were expensed and not tax effected, as the Company currently records no income tax expense. All common shares issued 

upon exercise or vesting are reserved and non-assessable. 

At December 31, 2008, the Company had unvested stock options to purchase 1,799,167 common shares with a weighted average grant date 

fair value of $1.34 per common share and 2,533,898 restricted common shares outstanding having a weighted average grant date value of $2.02 

per common share. As of December 31, 2008, the 

 

F-25 

 

Number of 

Shares Under 

Stock Options 

Weighted 

Average 

Grant Date 

Fair Value 

Restricted common shares outstanding as of December 31, 2007 1,096,000 $ 2.15 

Restricted common shares granted 1,745,343 $ 1.90 

Restricted common shares vested — $ — 

Restricted common shares cancelled (307,445 ) $ 1.83 

 

Restricted common shares outstanding as of December 31, 2008 2,533,898 

 

 

 

 

Restricted 

Common Shares 

Outstanding 

Grant Date 

Fair Value 

July 3, 2007 (July 3, 2011) 972,250 $ 2.20 

May 16, 2008 (May 16, 2012) 1,516,648 $ 1.91 

August 18, 2008 (August 18, 2012) 45,000 $ 1.75 

 

Total 2,533,898 

 

 As of December 31, 

 2008 2007 2006 

 

(in thousands, except 

per share data) 

Total value of restricted common shares outstanding $ 836 $ 1,370 $ — 

Weighted average grant date fair value per share of restricted common share outstanding $ 2.02 $ 2.15 $ — 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

Company had approximately $4.0 million of total unrecognized compensation cost related to unvested stock options and restricted common 

shares, which is expected to be amortized over the following periods: 

 

8. Commodity Hedging Contracts 

The Company maintains a commodity-price risk-management strategy that uses derivative instruments to minimize significant, 

unanticipated earnings fluctuations that may arise from volatility in commodity prices. The Company uses natural gas costless collars, index 

swaps, basis swaps and put options to hedge commodity price risk. 

Effective October 1, 2008, the Company elected to discontinue hedge accounting on all existing derivative contracts and elected not to 

designate any additional derivative contracts that were entered into subsequent to that date as cash flow hedges under SFAS No. 133. Derivative 

contracts are carried at their fair value on the balance sheet and all unrealized gains and losses are recorded in the statement of operations in 

unrealized natural gas hedge income (loss), while realized gains and losses related to contract settlements are recognized in natural gas and oil 

revenues. 

The following derivative transactions were outstanding with associated notional volumes and hedge prices for the index specified as of 

December 31, 2008: 

 

 

 

 

 

 

 

 

F-26 

 Amount 

 (in thousands) 

2009 $ 2,230 

2010 1,249 

2011 524 

 

Total $ 4,003 

 

Date Period 

Derivative 

Instrument (1) 

Notional 

Daily 

Volume 

Notional 

Volume 

Remaining 

Base 

Fixed 

Price Puts Calls Index 

Production 

Area 

Hedged 

 (MMBtu) (MMBtu) (MMBtu) (MMBtu) 

10/15/08 Cal 09 CC 5,000 1,825,000 — $ 8.00 $ 12.05 Nymex-HH TX 

04/24/08 Cal 09 CC 5,000 1,825,000 — $ 9.00 $ 11.85 HSC (2) TX 

10/15/08 Cal 09 B 5,000 1,825,000 -$ 0.3800 — — HSC (2) TX 

10/15/08 Cal 09 I 5,000 1,825,000 — — — HSC (2) TX 

12/10/08 Jan-Feb 09 P 5,000 450,000 — $ 5.50 — Nymex-HH TX 

12/10/08 Jan-Feb 09 (P) 5,000 450,000 — $ 5.00 — Nymex-HH TX 

11/14/08 Cal 09 B 1,500 547,500 -$ 2.2200 — — CIG (3) WY 

11/21/08 Cal 09 B 1,000 365,000 -$ 2.0200 — — CIG (3) WY 

 

(1) CC = Costless collars. 

(1) B = Basis swaps. 

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

(1) P = Puts purchased. 

(1) (P) = Puts sold. 

(2) East-Houston-Katy—Houston Ship Channel. 

(3) Inside FERC Colorado Interstate Gas, Rocky Mountains. 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

As of December 31, 2008, all of the Company’s economic derivative hedge positions were with a multinational energy company of high 

credit quality, which is not known to the Company to be in default on their derivative positions. The credit support for the Company’s 

outstanding hedges at year-end is under the Revolving Credit Facility through intercreditor agreements. The Company also had a $100,000 letter 

of credit outstanding with an additional derivative counter party but did not have any derivative contracts outstanding with that party at year-end. 

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 discussed above; however, the Company 

believes credit risk is minimal and does not anticipate such nonperformance. Based on the Company’s projections, approximately 37% of its 

2009 estimated natural gas production was hedged as of December 31, 2008. 

The Company recorded a short-term derivative asset of $9.8 million and a short-term derivative liability of $1.1 million related to the 

difference between hedged commodity prices and market prices on hedged volumes as of December 31, 2008, after application of SFAS 

No. 157. None of the Company’s derivative instruments are designated as cash flow hedging instruments as of December 31, 2008. For the 

twelve months ended December 31, 2008, the Company recognized unrealized gains in the statement of operations of $6.5 million related to the 

change in the fair value of its derivative instruments. 

9. Fair Value Measurements 

Fair Value Measurements. In September 2006, the FASB issued 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. 

SFAS No. 157 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy 

prioritizes the inputs into three broad levels as follows: 

 

 

 

 

F-27 

 

• Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. The Company’s cash equivalents 

consist of short-term, highly liquid investments, which have maturities of 90 days or less, including sweep investments and money 

market funds. 

 

• Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or 

liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument. 

 

• Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value 

measurement and less observable from objective sources. The Company’s valuation models consider various inputs including 

(a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the 

underlying instruments. Level 3 instruments are natural gas zero cost collars, index swaps, basis swaps and put options. Although the 

Company utilizes third party broker quotes to assess the reasonableness of prices and valuation techniques, the Company does not 

have sufficient corroborating market evidence to support classifying these instruments as Level 2. 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

A financial asset’s or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the 

fair value measurement. The determination of the fair values below incorporates various factors required under SFAS No. 157, including the 

impact of the counterparty’s non-performance risk with respect to the Company’s financial assets and the Company’s non-performance risk with 

respect to the Company’s financial liabilities. The following table provides the assets and liabilities carried at fair value measured as of 

December 31, 2008: 

 

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair 

value hierarchy for the year ended December 31, 2008: 

 

10. Common Shares 

Authorized 

The Company’s articles of incorporation allow the Company to issue an unlimited number of common shares without par value. 

Other Share Issuances 

On February 3, 2006, the Company issued 21,948 common shares upon exercise of warrants at CDN$4.65 per share issued in connection 

with the sale of the Convertible Subordinated Debentures. 

On March 20, 2006, the six-month anniversary of the September 19, 2005 $10.0 million senior secured notes issuance, the Company issued 

to the note holders an additional 152,299 common shares valued at CDN$714,286. 

 

F-28 

 As of December 31, 2008 

 Level 1 Level 2 Level 3 Total 

 (in thousands) 

Asset: 

Cash equivalents $ 6,153 $ — $ — $ 6,153 

Commodity derivatives $ — $ — $ 9,829 $ 9,829 

Liabilities: 

Commodity derivatives $ — $ — $ 1,121 $ 1,121 

 

Derivatives For 

the Year Ended 

December 31, 2008 

 (in thousands) 

Balance as of January 1, 2008 $ (391 ) 

Total gains or losses (realized or unrealized): 

Included in earnings (1) 4,422 

Included in other comprehensive (loss) income 2,629 

Purchases, issuances and settlements 2,048 

Transfers in and out of Level 3 — 

 

Balance as of December 31, 2008 $ 8,708 

 

 

Changes in unrealized gain relating to derivatives still held as of December 31, 2008 $ 6,529 

 

 

 

(1) This amount is included in total revenues on the statement of operations. 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

On March 31, 2006, the Company issued 548,128 common shares at CDN$4.50 in a private placement in settlement of a purchase price 

adjustment on the acquisition of natural gas and oil properties. 

On June 19, 2006, the twelve-month anniversary of the June 17, 2005 $63.0 million senior secured notes issuance, the Company issued to 

the note holders an additional 1,607,143 common shares valued at CDN$4.5 million. 

On September 19, 2006, the twelve-month anniversary of the September 19, 2005 $10.0 million senior secured notes issuance, the 

Company issued to the note holders an additional 256,016 common shares valued at CDN$714,286. 

On November 17, 2006, the Company issued 25,000,000 common shares at $2.00 in a private transaction to institutional investors. 

On December 19, 2006, the eighteen-month anniversary of the June 17, 2005 $63.0 million senior secured notes issuance, the Company 

issued to the note holders an additional 1,800,000 common shares valued at CDN$4.5 million. 

During the year ended December 31, 2006, pursuant to the Company’s Stock Option Plan, the Company issued 905,636 common shares 

net of forfeitures in connection with the cashless exercise of stock options. 

On March 19, 2007, the eighteen-month anniversary of the September 19, 2005 $10.0 million senior secured notes issuance, the Company 

issued to the note holders an additional 375,939 common shares valued at CDN$714,286. 

On May 9, 2007, in conjunction with the sale of a portion of the Company’s East Texas undeveloped natural gas and oil acreage to a third 

party, the Company issued 10,000,000 common shares at a price of $2.00 per share, or $20.0 million. 

On May 23, 2007 in conjunction with the May 9, 2007 sale of 10,000,000 common shares, Chesapeake acquired an additional 1,757,195 of 

the Company’s common shares at $2.00 per share pursuant to its preemptive rights under a Common Stock Purchase Agreement dated 

November 4, 2005. 

During the year ended December 31, 2007, pursuant to the Company’s 2006 Gastar Long-Term Stock Incentive Plan, the Company issued 

1,096,000 restricted common shares (net of 9,000 common shares which were cancelled) to employees, subject to vesting. 

During the year ended December 31, 2008, pursuant to the Company’s 2006 Gastar Long-Term Stock Incentive Plan, the Company issued 

1,437,898 restricted common shares (net of 307,445 common shares which were cancelled) to employees, subject to vesting. 

Shares Reserved 

At December 31, 2008, the Company has reserved 26,730,586 common shares to be issued pursuant to the conversion of Convertible 

Subordinated Debentures (6,849,315 common shares), exercise of stock options (9,648,750 common shares) and the exercise of warrants 

(10,232,521 common shares). 

 

F-29 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

11. Warrants 

The following table summarizes warrant information to purchase common shares as of December 31, 2008: 

 

12. Interest and Debt Extinguishment Expense 

The following tables summarize the components of interest and debt extinguishment expense: 

 

13. Related Party Transactions 

Chesapeake Energy Corporation 

On November 4, 2005, the Company completed an integrated transaction with Chesapeake whereby Chesapeake acquired 27,151,641 

newly issued Company common shares equal to 19.9% of the then outstanding common shares, acquired a 33.3% working interest in the 

Company’s Bossier play in the Hilltop area of East Texas. As part of this transaction, Chesapeake paid an additional $7.8 million, before fees 

and expenses, to reimburse the Company for Chesapeake’s pro rata share of leasehold interests acquired and to pay a 

 

F-30 

 

Number of 

Warrants 

Fair 

Value of 

Warrant 

(in thousands) 

Warrant 

Price per 

Share 

Range 

Weighted 

Average 

Remaining 

Life in 

Years 

Weighted 

Average 

Exercise 

Price in 

US$ 

Warrants issued in connection with $3.25 million 

subordinated unsecured notes payable 232,521 $ 235 $ 2.76-3.03 0.3 $ 2.80 

Warrant issued in connection with the GeoStar litigation 

settlement 10,000,000 $ 5,388 (1 ) 2.9 $ (1 ) 

 

(1) The warrant is exercisable for $2.75 per share in the event that, on or before June 11, 2011, the Company sells all or substantially all of its 

present oil and gas interests located in Leon and Robertson Counties in East Texas for net proceeds exceeding $500.0 million. A sale, or a 

series of sales, of all or substantially all of the Company’s present East Texas properties prior to June 11, 2011 for $500.0 million or less 

will terminate the warrant. If the Company does not sell all or substantially all of these properties by June 11, 2011, the warrant will be 

exercisable for a six-month period commencing on that date at $3.00 per share. The Company is not obligated to sell any of its East Texas 

properties. 

 For the Years Ended December 31, 

 2008 2007 2006 

 (in thousands) 

Interest expense: 

Cash and accrued $ 16,080 $ 11,702 $ 11,339 

Amortization of deferred financing costs and debt discount 1,998 4,235 4,260 

Capitalized interest (12,225 ) (1,858 ) — 

 

Total interest expense $ 5,853 $ 14,079 $ 15,599 

 

 

 

 

 

Early extinguishment of debt: 

Call premium — $ 3,650 — 

Unamortized deferred financing costs and debt discount — 12,034 — 

 

Total debt extinguishment expense $ — $ 15,684 $ — 

 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

disproportionate amount of future drilling costs in exchange for an undivided 33.3% of the Company’s leasehold working interests in the deep 

Bossier Hilltop prospect, less and except 160 acres surrounding each existing well bore. Chesapeake agreed to pay 44.44% of the drilling costs 

through casing point in the first six wells drilled by the parties in the Hilltop prospect to a depth sufficient to test the deep Bossier formation (an 

approximate depth of 19,000 feet) in order to earn its 33.33% leasehold working interest. The leasehold reimbursement was recorded as a 

reduction to natural gas and oil property cost. 

As a result of its purchase of common shares, Chesapeake has the right to negotiate exclusively with the Company for a period of 30 days 

on any proposed sale of assets. Additionally, Chesapeake has the right, with certain exceptions, to maintain its percentage ownership of the 

Company, on a fully diluted basis, by participating in future stock issuances and has the right to an observer being present at meetings of the 

Board of Directors. 

On November 11, 2006 and May 23, 2007, Chesapeake acquired an additional 5,000,000 common shares and 1,757,195 common shares, 

respectively, in private placement transactions. As of December 31, 2008, Chesapeake owned 33,908,836 common shares, or 16.2% of the 

Company’s outstanding common shares. 

All related balances are the result of well operations activity governed by an existing standard form joint operating agreement. All balances 

are typically due and payable within 30 days. 

14. Income Taxes 

Loss before income taxes for the three years ended December 31, 2008 is as follows: 

 

The reconciliation of the Company’s effective tax rates from the statutory rate for the three years ended December 31, 2008 are as follows: 

 

 

F-31 

 For the Years Ended December 31, 

 2008 2007 2006 

 (in thousands) 

United States $ (300 ) $ 336 $ (67,852 ) 

Foreign (5,061 ) (30,876 ) (16,987 ) 

 

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

 

 

 

 

 

 

 For the Years Ended December 31, 

 2008 2007 2006 

 (in thousands) 

Expected income tax benefit at statutory U.S. rates of 35% $ (1,876 ) $ (10,689 ) $ (29,694 ) 

State tax, tax effected 46 72 (1,222 ) 

Non-deductible stock-based compensation expense 1,095 1,270 1,252 

Deferred tax effect of change in Canadian tax rates 2,978 1,576 — 

Impact of Canadian capital gain tax rate on extinguishment income 180 1,197 — 

Impact of Canadian capital gain tax rate on foreign exchange gains — 2,390 — 

Expiring Canadian net operating losses 258 — — 

Other 148 37 1,141 

Change in valuation allowance (2,829 ) 4,147 28,523 

 

Actual income tax provision $ — $ — $ — 

 

 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

The components of the Company’s U.S. deferred taxes are comprised of the following: 

 

For U.S. federal income tax purposes, the Company has net operating loss carryforwards of approximately $143.6 million, which if not 

utilized will begin to expire in 2020. 

The Company has the following approximate undeducted Canadian tax pools: 

 

For Canadian income tax purposes, the Company has net operating loss carryforwards, which if not utilized will begin to expire in 2009 

through 2015. 

The components of the Company’s Canadian deferred tax assets are comprised of the following: 

 

The components of the Company’s Australian deferred taxes are comprised of the following: 

 

 

F-32 

 As of December 31, 

 2008 2007 

 (in thousands) 

Deferred tax asset (liability): 

Capital assets $ (19,903 ) $ (11,251 ) 

Net operating loss carryforwards 52,733 45,081 

Valuation allowance (32,830 ) (33,830 ) 

 

Net deferred tax asset $ — $ — 

 

 

 

 

 As of December 31, 

 2008 2007 

 (in thousands) 

Cumulative Canadian exploration expense $ 994 $ 987 

Cumulative Canadian development expense $ 192 $ 192 

Foreign exploration and development expense $ 689 $ 684 

Undeducted undepreciated capital costs $ 18 $ 24 

Undeducted share issue costs $ 1,546 $ 2,826 

Undeducted non-capital loss carryforwards $ 59,656 $ 53,681 

Undeducted senior secured note issue costs $ 1,373 $ 2,352 

 As of December 31, 

 2008 2007 

 (in thousands) 

Deferred tax assets: 

Capital assets $ 463 $ 551 

Senior and senior secured note issue costs 860 1,664 

Net operating loss carryforwards 14,765 15,836 

Valuation allowance (16,088 ) (18,051 ) 

 

Net deferred tax asset $ — $ — 

 

 

 

 

 As of December 31, 

 2008 2007 

 (in thousands) 

Deferred tax asset (liability): 

Capital assets $ (4,637 ) $ (5,946 ) 

Net operating loss carryforwards 5,359 6,534 

Valuation allowance (722 ) (588 ) 

 

Net deferred tax asset $ — $ — 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

For Australian income tax purposes, the Company has net operating loss carry forwards of approximately $17.8 million. There is currently 

no time limit on the utilization of tax losses in Australia. Ability to use Australian tax losses is based on statutory tests. 

In June 2006, the FASB issued FIN 48. FIN 48 requires that the Company recognize the financial statement benefit of a tax position only 

after determining that the relevant tax authority would more likely than not sustain the position following an audit. For a tax position meeting the 

more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of 

being realized upon ultimate settlement with the relevant tax authority. The Company did not have any unrecognized tax benefits and there was 

no effect on our financial condition or results of operations as a result of implementing FIN 48. 

It is expected that the amount of unrecognized tax benefits may change in the next twelve months; however, the Company does not expect 

the change to have a significant impact on financial condition or results of operations. As of December 31, 2008, the Company had no 

unrecognized tax benefits that if recognized would affect the effective tax rate. 

The Company is subject to examination of income tax filings in the U. S., various state jurisdictions and the foreign jurisdictions of Canada 

and Australia for the tax periods 2000 and forward due to the Company’s continued loss position in such jurisdictions. 

Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of 

general and administrative expense in the consolidated statement of operations. The Company has not recorded any interest or penalties 

associated with unrecognized tax benefits. 

15. Earnings or Loss per Share 

In accordance with the provisions of SFAS No. 128, basic earnings or loss per share is computed on the basis of the weighted average 

number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average 

number of common shares plus the assumed issuance of common shares for all potentially dilutive securities. Diluted amounts are not included 

in the computation of diluted loss per share, as such would be anti-dilutive. 

 

 

F-33 

 For the Years Ended December 31, 

 2008 2007 2006 

 (in thousands, except per share and share data) 

Basic and diluted loss and shares outstanding: 

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

Weighted average common shares outstanding 207,098,570 202,828,792 170,014,733 

Basic and diluted loss per common share: 

Net loss per share applicable to all common shares $ (0.03 ) $ (0.15 ) $ (0.50 ) 

Common shares excluded from denominator as anti-dilutive: 

Stock options 9,648,750 10,173,750 10,472,750 

Unvested restricted common shares 2,533,898 1,096,000 — 

Warrants 10,232,521 232,521 2,732,521 

Convertible subordinated debentures 6,849,315 6,849,315 6,849,315 

Liability to be settled by issuance of common shares (1) — — 288,018 

 

Total 29,264,484 18,351,586 20,342,604 

 

 

 

 

 

 

 

(1) December 31, 2006 assumes conversion of the liability to be settled by issuance of common shares for the senior secured notes at a year 

end closing price of CDN$2.48 per common share. 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

16. Commitments and Contingencies 

Operating Leases 

The Company leases its office facilities, certain gas treatment facilities and certain office equipment under non-cancelable operating lease 

agreements. For the years ended December 31, 2008, 2007 and 2006, office lease expense totaled approximately $240,000, $205,000 and 

$184,000, respectively. For the years ended December 31, 2007 and 2006, gas treatment lease payments were approximately $565,000 and 

$777,000, respectively. The gas treatment leases were cancelled in late 2007. 

As of December 31, 2008, the Company’s operating leases for the indicated periods were as follows: 

 

Litigation 

The Company is party to various litigation matters arising out of the normal course of business. The ultimate outcome of the matters 

discussed below cannot presently be determined, nor can the liability that could potentially result from an adverse outcome be reasonably 

estimated at this time. The Company does not expect that the outcome of these proceedings will have a material adverse effect on its financial 

position, results of operations or cash flow. The more significant litigation matters are summarized below. 

Navasota Resources L.P. (“Navasota”) vs. First Source Texas, Inc., First Source Gas L.P. (now Gastar Exploration Texas LP) and Gastar 

Exploration Ltd. (Cause No. 0-05-451) District Court of Leon County, Texas 12th Judicial District . This lawsuit, dated October 31, 2005, 

contends that the Company breached Navasota’s preferential right to purchase 33.33% of the Company’s interest in certain natural gas and oil 

leases located in Leon and Robertson Counties and sold to Chesapeake Energy Corporation pursuant to a transaction closed November 4, 2005. 

The preferential right claimed is under an operating agreement dated July 7, 2000. The Company contends, among other things, that Navasota 

neither properly nor timely exercised any preferential right election it may have had with respect to the inter-dependent Chesapeake transaction. 

In July 2006, the District Court of Leon County, Texas issued a summary judgment in favor of the Company and Chesapeake. Navasota filed a 

Notice of Appeal to the Tenth Court of Appeals in Waco. Oral argument was heard on September 26, 2007 and the Court of Appeals issued its 

opinion on January 9, 2008 reversing the trial court’s rulings, rendering judgment in favor of Navasota on its claims for breach of contract and 

specific performance, and remanding the case for further proceedings on Navasota’s other counts, which include claims for suit to quiet title, 

trespass to try title, tortious interference with contract, conversion, money had and received, and declaratory relief. The Company and 

Chesapeake filed a motion for rehearing on February 6, 2008, which was denied on March 18, 2008. The Company and Chesapeake filed a joint 

Petition for Review in the Texas Supreme Court on May 13, 2008. On August 28, 2008, the Texas Supreme Court requested briefing on the 

merits. On January 9, 2009, the Texas Supreme Court denied the Petition for Review. On January 26, 2009, the Company and Chesapeake 

jointly filed a motion for rehearing in the Texas Supreme Court on its denial of the Petition for Review, which prompted the Texas Supreme 

Court to request additional responsive briefing from Navasota by March 10, 2009. 

 

F-34 

 For the Year Ending December 31, 

 Total 2009 2010 2011 2012 Thereafter 

 (in thousands) 

Office lease $ 444 $ 264 $ 180 $ — $ — $ — 

Operating leases and other 15 8 7 — — — 

 

Total $ 459 $ 272 $ 187 $ — $ — $ — 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

Pursuant to a provision in the November 4, 2005 Purchase and Sale and Exploration Development Agreement with Chesapeake, 

Chesapeake acknowledged the existence of the Navasota lawsuit and claims and further agreed that if Navasota were to prevail on its claims, that 

Chesapeake would convey the affected interests it purchased from the Company to Navasota upon receipt of the purchase price and/or other 

consideration paid by Navasota. Therefore, the Company believes that if Navasota seeks to exercise rights of specific performance, its doing so 

should impact only Chesapeake’s assigned leasehold interests. However, in December 2008, Chesapeake stated to the Company that if the Texas 

Supreme Court were not to reverse the decision of the Tenth Court of Appeals, Chesapeake would seek rescission of the 2005 transaction and 

restitution of consideration paid. Chesapeake may assert such rescission and restitution as to the November 4, 2005 Purchase and Sale and 

Exploration Development Agreement; a November 4, 2005 Exploration and Development Agreement; and a November 4, 2005 Common Share 

Purchase Agreement. In its December 2008 communication, Chesapeake did not identify particular sums as to which it may seek restitution, but 

amounts paid to the Company in connection with the 2005 transaction could be asserted to include the $76.0 million paid by Chesapeake for the 

purchase of 27.2 million common shares as part of the transaction in 2005 and/or other amounts. Chesapeake has not further advised the 

Company of its intentions with respect to any rescission or restitution claim since the Texas Supreme Court issued its denial of the Petition for 

Review, and Navasota has not further advised the Company of its intentions with respect to acquiring any of the interests assigned to 

Chesapeake. If Chesapeake were to seek rescission or restitution, the Company would vigorously defend any such action. 

In addition, while the Navasota Resources litigation is pending, it is possible that expenditures incurred, or authorizations for proposed 

expenditures, for drilling activities on leases which include the disputed interest may remain unpaid or not be authorized by the non-operators 

asserting competing ownership rights, which could require the Company to either fund a disproportionate amount of drilling costs at its own risk 

or postpone its drilling program on affected leases. 

Gastar Exploration Texas LP v. John E. McFarlane, et al (Cause No. 0-06-161) 87th Judicial District Court of Leon County, Texas . This 

suit to quiet title to an undivided 25% mineral interest under an oil and gas lease dated December 4, 2003, covering approximately 2,598 gross 

acres was settled on November 28, 2008. Pursuant to the settlement, the lease royalty burden was increased from 22.5% to 25.0% effective 

December 1, 2008. In conjunction with the settlement, the Company released all previously held suspended revenues regarding the disputed 

interest. 

Craig S. Tillotson v. S. David Plummer 2 nd , Spencer Plummer 3 rd , Tony Ferguson, John Parrott, Thomas Robinson, GeoStar 

Corporation, First Source Wyoming, Inc. GeoStar Financial Services Corporation, Gastar Exploration Ltd., Zeus Investments, LLC and John 

Does 1-10 (Civil No. 080412334). This lawsuit was filed on July 7, 2008 in Utah state court by Craig S. Tillotson (“Tillotson”), in which he 

alleges that he was fraudulently induced to invest in a mare leasing program operated by Classic Star LLC, a subsidiary of GeoStar, on the basis 

of certain verbal representations, and to convert interests in that program into shares of a working interest in the Powder River Basin. Tillotson 

asserts causes of action against all defendants including common law fraud, fraudulent inducement, statutory securities fraud under Utah state 

law, civil conspiracy, and negligent misrepresentation, and asserts certain additional causes of action only against GeoStar, a GeoStar affiliate, 

and David and Spencer Plummer. The Company has not been served and has not yet answered or otherwise responded. The Company intends to 

vigorously defend the suit. 

Fridkin-Kaufman Ltd. v. Gastar Exploration Texas L.P. f/k/a First Source Gas L.P., Gastar Exploration Ltd., First Texas Gas, L.P., First 

Source Texas, Inc., Gastar Exploration Texas, Inc. f/k/a First Texas Development, Inc., and Navasota Resources, Ltd. f/k/a Navasota Resources, 

Inc. ; in the District Court of Harris County, Texas, 281 st Judicial District (Case No. 2008-74765). This lawsuit was filed on December 19, 2008, 

alleging that the defendants have failed to properly pay royalty on production from the Fridkin-Kaufman #1 well 

 

F-35 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

in Leon County, Texas during the period January 2005 to present. Plaintiff seeks damages of approximately $400,000, plus interest and 

attorney’s fees. The Company was served recently and has answered denying all claims. The Company intends to vigorously defend the suit. 

In re ClassicStar Mare Lease Litigation and Gregory R. Raifman, individually and as Trustee of the Raifman Family Revocable Trust 

Dated 7/2/03, Susan Raifman, individually and as Trustee of the Raifman Family Revocable Trust Dated 7/2/03, and Gekko Holdings, LLC, 

d/b/a Gekko Breeding and Racing v. ClassicStar LLC, ClassicStar Farms, LLC, Strategic Opportunity Solutions, LLC d/b/a Buffalo Ranch, 

GeoStar Corporation, S. David Plummer, Spencer D. Plummer III, Tony Ferguson, Thomas Robinson, John Parrot, Karren Hendrix, Stagg 

Allen & Company, P.C. f/k/a Karren Hendrix & Associates, P.C., Terry L. Green, ClassicStar Farms, Inc., Gastar Exploration, Ltd. and Does 1-

1,000; In the United States District Court for the Eastern District of Kentucky (Cause No. 5:07-cv-347-JMH, Master File No. 5:07-cv-353-

JMH). This lawsuit was filed on February 2, 2009 in federal court in Kentucky as part of a multi-district litigation proceeding, naming the 

Company as one of the several defendants. The plaintiffs allege that they were defrauded into participating in a mare leasing program operated 

by the defendants, and had been promised options to convert interests in the mare leasing program for working interests in wells or shares of 

Company stock owned by defendants other than the Company. The plaintiffs assert several causes of action against all defendants, including 

violations of the RICO Act, common law fraud, negligent misrepresentation, constructive trust, unjust enrichment, and negligence. The plaintiffs 

also assert additional causes of action only against the ClassicStar defendants, David and Spencer Plummer, Karren Hendrix, Terry Green, 

Strategic Opportunity Solutions, and Does 1-1,000. The Company has not yet appeared, answered, or otherwise responded. The Company 

intends to vigorously defend the suit. 

In re ClassicStar Mare Lease Litigation and West Hill Farms, LLC, et al. v. ClassicStar LLC, ClassicStar Farms, LLC, ClassicStar 2004, 

LLC, National Equine Lending Co., LLC, New NEL, LLC, GeoStar Corp., GeoStar Equine Energy, Inc., Tony Ferguson, David Plummer, 

ClassicStar Thoroughbreds, LLC, Spencer Plummer, Karren Hendrix Stagg Allen & Co., Thom Robinson, John Parrot, First Equine Energy 

Partners, LLC, Strategic Opportunity Solutions, LLC d/b/a Buffalo Ranch, ClassicStar 2005 Powerfoal Stables, LLC, ClassicStar Farms, Inc., 

GeoStar Financial Services Corp., Gastar Exploration, Ltd., and John Does 1-3; In the United States District Court for the Eastern District of 

Kentucky (Cause No. 06-243-JMH, Master File No. 5:07-cv-353-JMH). This lawsuit was filed on February 2, 2009 in federal court in Kentucky 

as part of a multi-district litigation proceeding, naming the Company as one of several defendants. The plaintiffs allege that they were defrauded 

participating in a mare leasing program operated by the defendants, and had been promised options to convert interests in the mare leasing 

program for working interests in wells or shares of Company stock owned by defendants other than the Company. The plaintiffs assert several 

causes of action against the majority of the defendants, including the Company. These causes of action include violations of the RICO Act, 

common law fraud, negligent misrepresentation, theft by deception, unjust enrichment, conspiracy, aiding and abetting, and fraudulent transfer. 

The plaintiffs also assert additional causes of action against certain defendants other than the Company for breach of contract, state and federal 

securities fraud, anticipatory breach, and conversion. The Company has not yet appeared, answered, or otherwise responded. The Company 

intends to vigorously defend the suit. 

In re ClassicStar Mare Lease Litigation and AA-J Breeding, LLC, Su-Sim, LLC, Derby Stakes, LLC, Uri Halfon, and Ora-Oli Halfon v. 

GeoStar Corp., GeoStar Financial Services Corp., First Source Wyoming, Inc., ClassicStar, LLC, ClassicStar Farms, LLC, ClassicStar Farms, 

Inc., Karren Hendrix, Stagg, Allen, & Company, P.C., f/k/a Karren, Hendrix & Assoc. P.C., Handler, Thayer, & Duggan, LLC, Thomas J. 

Handler, J.D., P.C., S. David Plummer, Spencer D. Plummer III, Tony Ferguson, Terry L. Green, and Gastar Exploration, Ltd.; In the United 

States District Court for the Eastern District of Kentucky (Cause No. 5:08-cv-79-JMH, Master File No. 5:07-cv-353-JMH). This lawsuit was 

filed on February 6, 2009 in federal court in Kentucky as part of a 

 

F-36 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

multi-district litigation proceeding, naming the Company as one of several defendants. The plaintiffs allege that they were defrauded into 

participating in a mare leasing program operated by the defendants, and had been promised options to convert interests in the mare leasing 

program for working interests in wells or shares of Company stock. The plaintiffs assert several causes of action against all defendants, including 

violations of the RICO Act, breach of contract, common law fraud, misrepresentation, constructive trust, unjust enrichment, accounting, and 

conversion. The plaintiffs also assert additional causes of action only against Karren Hendrix, Handler, Thayer, & Duggan, LLC, and Thomas J. 

Handler. The Company has not yet appeared, answered, or otherwise responded. The Company intends to vigorously defend the suit. 

Gastar Exploration Texas L.P. vs. J. Ken Welch d/b/a W-S-M Oil Company, et al; Cause No. 0-09-117 in the 87 th Judicial District Court 

of Leon County, Texas. This is a suit for trespass to try title and, in the alternative, to quiet title, to an undivided mineral interest under several 

Gastar oil & gas leases covering approximately 4,273.70 gross acres (the “Leases”). In this suit Gastar contends that certain oil and gas leases 

claimed by the defendants’ have expired according to their terms and that the defendants’ failure to release those leases constitutes a trespass 

upon and cloud on the Leases. This lawsuit was recently filed and the Defendants have not yet responded to Gastar’s Original Petition. Gastar 

will continue to vigorously pursue this claim. 

Settlement with GeoStar Corporation and Affiliates 

On June 11, 2008, the Company entered into a settlement agreement with GeoStar to resolve all outstanding disputes and lawsuits between 

the companies, including settlement of a claim for certain “look-back” payments arising under agreements related to the purchase of certain East 

Texas properties by the Company from GeoStar. The settlement included cash payments by the Company of approximately $29.0 million, plus 

the issuance to GeoStar of a warrant to purchase 10.0 million of the Company’s common shares (the “Warrant”). Pursuant to the settlement, 

GeoStar assigned to the Company all of GeoStar’s natural gas and oil interests in West Virginia, while the Company acknowledged GeoStar’s 

clear title to an exploration license (EL 4416) and assigned to GeoStar its interest in an exploration license application (EL 4968), both located in 

Victoria, Australia. As of the settlement date, EL 4416 and EL 4968 had no attributable proved reserves or production. In addition, the Company 

released its claim to GeoStar on approximately 340 acres in East Texas that were in dispute. Certain other corrective lease assignments and 

releases are being made between the Company and GeoStar. The Company and GeoStar have mutually agreed to release all claims against each 

other, their affiliates and current and past officers and directors. 

As part of the settlement, GeoStar has the right to farm-in from the Company two Hilltop well locations in East Texas. The designated 

farm-in area is not included in the Company’s future Bossier or Knowles drilling plans and does not include any proven or probable reserves. 

The Warrant is exercisable for $2.75 per share in the event that on or before June 11, 2011, the Company sells up to all or substantially all 

of its present natural gas and oil interests located in Leon and Robertson Counties in East Texas for net proceeds exceeding $500.0 million. A 

sale, or a series of sales, of all or substantially all of the Company’s present East Texas properties prior to June 11, 2011 for $500.0 million or 

less will terminate the Warrant. If the Company does not sell all or substantially all of these properties by June 11, 2011, the Warrant will be 

exercisable for a six-month period commencing on that date at $3.00 per share. The Company is not obligated to sell any of its East Texas 

properties. 

 

F-37 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

As a result of the settlement with GeoStar, the Company had, net of the fair market value of Australian properties conveyed and the West 

Virginia properties received, a net increase in natural gas and oil properties of $31.5 million as of December 31, 2008. Major components of this 

increase in natural gas and oil properties are as follows: 

 

Commitments 

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. 

Restoration, Removal and Environmental Liabilities 

The Company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, 

in addition to contractual agreements and management decisions, result in the accrual of estimated future removal and site restoration costs. 

These costs are initially measured at a fair value and are recognized in the consolidated financial statements as the recent value of expected 

future cash flows. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation 

(accretion expense) and the amortization of the asset retirement obligation cost are recognized in the results of operations. Costs attributable to 

these commitments and contingencies are expected to be incurred over an extended period of time and are to be funded mainly from the 

Company’s cash provided by operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this 

time, it could be material for any quarter or year. 

 

F-38 

 Amount 

 (in thousands) 

Cash payment $ 28,997 

Value of warrant issued to GeoStar 5,388 

Net forgiveness of GeoStar receivables, payables, related accruals and other (2,912 ) 

 

Net increase in natural gas and oil properties related to settlement 31,473 

Fair market value of properties conveyed (received): 

Australia EL 4416 9,015 

West Virginia (882 ) 

 

Gross settlement value $ 39,606 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

Indemnifications 

Indemnifications in the ordinary course of business have been provided pursuant to provisions of purchase and sale contracts, service 

agreements, joint venture agreements, operating agreements and leasing agreements. In these agreements, the Company may indemnify 

counterparties if certain events occur. These indemnification provisions vary on an agreement by agreement basis. In some cases, there are no 

pre-determined amounts or limits included in the indemnification provisions and the occurrence of contingent events that will trigger payment, if 

any, is difficult to predict. 

Employment Agreements 

The Company entered into employment agreements with its President and Chief Executive Officer and its Chief Financial Officer, 

effective February 24, 2005 (as amended July 25, 2008) and May 17, 2005 (as amended July 25, 2008), respectively. The agreements set forth, 

among other things, annual compensation, and adjustments thereto, minimum bonus payments, termination provisions, fringe benefits, 

termination and severance provisions. The agreements renew annually; however, they may be terminated at any time with or without cause. 

We also have entered into agreements with these executives, who are acting at the Company’s request to be officers of the Company, to 

indemnify them the fullest extent permitted by law, against any and all damages, liabilities, costs, charges or expenses suffered by or incurred by 

the individuals as a result of their service. The nature of the indemnification agreements prevents the Company from making a reasonable 

estimate of the maximum potential amount it could be required to pay to beneficiary of such indemnification agreement. 

17. Concentration of Risk and Significant Customers

Approximately 77%, 80% and 66% of the Company’s revenues for the years ended December 31, 2008, 2007 and 2006, respectively, were 

from production from producing wells in the Hilltop area East Texas. 

During 2008, ETC and Enserco Energy, Inc. (“Enserco”) accounted for 79% and 19% of the Company’s natural gas and oil revenues 

before realized natural gas hedges, respectively. During 2007, ETC and Enserco Energy, Inc. (“Enserco”) accounted for 78% and 20% of the 

Company’s natural gas and oil revenues, respectively. During 2006, ETC and Enserco accounted for 63% and 25% of the Company’s natural gas 

and oil revenues, respectively. Although ETC is the major natural gas purchaser and transporter in the area of Gastar’s deep Bossier play and 

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 thus minimizing a long-term material adverse impact on the Company’s 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 the financial position or results of operations of the Company, as there are numerous other purchasers operating in the Powder 

River Basin. 

 

F-39 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

18. Subsequent Events 

On February 16, 2009, concurrent with the execution of consents of a majority of the noteholders of the 12 3 / 4 % Senior Secured Notes to 

various amendments and modifications to the Indenture, Gastar USA and the Company entered into a Term Loan with a new lender and a 

Waiver and Second Amendment to the Revolving Credit Agreement. Following is summary of certain of the various agreement amendments, 

modifications and terms: 

12 3 / 4 % Senior Secured Notes due 2012 

Gastar USA, the Company and the Guarantors entered into a supplemental indenture supplementing, amending and modifying the 

Indenture, among other matters, as follows: 

 

 

 • Allowing incurrence of up to $55.0 million of first priority indebtedness including the Revolving Credit Facility and Term Loan; 

 

 

• Providing that in the event the Company or any of its subsidiaries sells assets in East Texas the net proceeds from such sale to be 

utilized to repay any debt outstanding under the Revolving Credit Facility and Term Loan and any remaining net proceeds to be used 

for the pro rata redemption of the 12 3 / 4 % Senior Secured Notes at stated premiums; 

 

Term Loan 

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. The Term Loan bears interest at a fixed rate of 20% per annum and matures on February 15, 

2012. 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 financial ratios consistent to the 

Revolving Credit Facility. 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 and 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. 

Amounts outstanding under the Term Loan are secured by a first priority lien on Gastar USA’s and certain subsidiaries’ primary oil and 

gas assets and certain other properties. In order to provide that the liens securing amounts outstanding under the Term Loan and other existing 

and future indebtedness incurred under the Company’s existing Revolving Credit Facility are and remain senior to the liens securing the 12 3 / 4 

% Senior Secured Notes. 

On March 13, 2009, concurrent with the execution of the Third Amendment, the Company 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 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. 

 

F-40 

 

• Allowing that net proceeds up to $60.0 million from non-East Texas asset sales before February 1, 2011 may be reinvested during the 

first 360 days from the closing date in existing properties with uninvested net proceeds in excess of $5.0 million after 360 days to be 

used for the repayment of amounts outstanding under the Revolving Credit Facility, the Term Loan, and for the pro rata redemption 

of the 12 3 / 4 % Senior Secured Notes at stated premiums; and 

 • Continuing restrictions on Company dividends and other restricted payments. 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

Revolving Credit Facility 

On February 16, 2009, Gastar USA, the Company and certain subsidiaries of the Parent entered into the Waiver and Second Amendment to 

the Revolving Credit Agreement (the “Second Amendment”) to provide for the waiver of a breach of a 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 requiring the Company to maintain a ratio of current assets to current liabilities of 1.0 to 1.0. The 

Second Amendment also amends, among other matters, the following: 

 

 

 

 

 

 

On March 13, 2009, Gastar USA, the Company, certain of its 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 the Company’s auditors issuance of a going concern statement in its report on our 

2008 consolidated financial statements. 

 

F-41 

 • Allow for the Term Loan to rank pari passu with the Revolving Credit Facility on liens; 

 

• Borrowings bear interest at a prime rate or LIBOR rate, plus in each case an applicable margin. The applicable interest rate margin 

varies from 0.25 to 1.0% in the case of borrowings based on the prime rate and from 2.5% to 3.25% in the case of borrowings based 

on the LIBOR rate, depending on the utilization level in relation to the borrowing base subject to a minimum borrowing interest rate 

of 5.0%; 

 • Annual commitment fee, ranging from 0.50% to 0.75% depending on borrowing base utilization; 

 • Borrowing base of $18.0 million and monthly amortization of $1.0 million per month commencing March 1, 2009; 

 

• 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 4.5 to 1.0 through December 31, 2009 and 4.0 to 1.0 for all quarters thereafter; and 

 

• Automatic extension of maturity date from October 15, 2009 to December 1, 2010 if requested by the Company 30 days prior to 

maturity of the Revolving Credit Facility provided that the Convertible Subordinated Debentures repayment has occurred or the 

lender has been provided with assurance, acceptable to the lender that such payment will occur. 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

19. Statement of Cash Flows—Supplemental Information 

The following is a summary of supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated financial 

statements: 

 

20. Quarterly Consolidated Financial Data—unaudited

 

 

F-42 

 For the Years Ended December 31, 

 2008 2007 2006 

 (in thousands) 

Cash paid for interest, net of capitalized interest $ 16,109 $ 10,825 $ 11,242 

Cash paid for debt extinguishment $ — $ 3,650 $ — 

Non-cash transactions: 

Non-cash capital expenditures excluded from accounts payable and accrued drilling costs $ (4,905 ) $ (2,516 ) $ 11,724 

Asset retirement obligation included in oil and gas properties $ 443 $ (108 ) $ 426 

Drilling advances application $ 5,384 $ 11,956 $ 5,482 

Common shares issued under senior secured notes $ — $ 606 $ 8,499 

GeoStar settlement $ 2,476 $ — $ — 

 For the Three Months Ended 

 

March 31, 

2008 

June 30, 

2008 

September 30, 

2008 

December 31, 

2008 

 (in thousands, except share and per share data) 

Revenues $ 15,433 $ 15,371 $ 15,897 $ 16,518 

Income (loss) from operations $ 2,397 $ 1,955 $ 3,777 $ (9,105 ) 

Income (loss) before income taxes $ 1,087 $ 546 $ 3,006 $ (10,000 ) 

Net income (loss) $ 1,087 $ 546 $ 3,006 $ (10,000 ) 

Income (loss) per share: 

Basic $ 0.01 $ 0.00 $ 0.01 $ (0.05 ) 

Diluted $ 0.01 $ 0.00 $ 0.01 $ (0.05 ) 

Weighted average number of shares: 

Basic 207,098,570 207,098,570 207,098,570 207,098,570 

Diluted 207,098,570 207,475,168 207,098,570 207,098,570 

 For the Three Months Ended 

 

March 31, 

2007 

June 30, 

2007 

September 30, 

2007 

December 31, 

2007 

 (in thousands, except share and per share data) 

Revenues $ 7,515 $ 7,956 $ 9,775 $ 9,319 

Loss from operations $ (7,374 ) $ (31,529 ) $ (2,517 ) $ (1,094 ) 

Income (loss) before income taxes (1) $ (10,955 ) $ 4,380 $ (5,526 ) $ (18,439 ) 

Net income (loss) (1) $ (10,955 ) $ 4,380 $ (5,526 ) $ (18,439 ) 

Income (loss) per share, basic and diluted $ (0.06 ) $ 0.02 $ (0.03 ) $ (0.09 ) 

Weighted average number of shares, basic and diluted 195,015,561 201,918,634 207,098,570 207,098,570 

 

(1) The three months ended June 30, 2007 includes a gain on sale of assets of $38.5 million. The three months ended December 31, 2007 

includes a loss on early debt extinguishment of $15.7 million. 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

21. Issuer Subsidiaries Condensed Consolidating Financial Statements 

The following table presents condensed consolidating balance sheets as of December 31, 2008 and 2007 and the related condensed 

consolidating statements of operations and condensed consolidating statements of cash flows for the three years ended December 31, 2008 of 

Gastar Exploration Ltd. (“Parent”), Gastar Exploration USA, Inc. (“Issuer”) and Gastar Exploration Texas, Inc., Gastar Exploration Texas LP, 

Gastar Exploration Texas LLC, Gastar Exploration New South Wales, Inc., Gastar Exploration Victoria, Inc. and Gastar Power Pty Ltd., a minor 

non-guarantor subsidiary included in issuer subsidiaries, (collectively referred to as “Issuer Subsidiaries”). Each of the Parent and the Issuer 

Subsidiaries, except for Gastar Power Pty Ltd., have fully and unconditionally guaranteed, on a joint and severally basis, the $100.0 million 12 

 3 / 4 % Senior Secured Notes sold in November 2007 and the Revolving Credit Facility, established at the same time. Interest is not charged on 

intercompany receivable or payables. 

 

F-43 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

Condensed Consolidating Parent and Issuer Subsidiaries Balance Sheets 

As of December 31, 2008 

 

 

F-44 

 Parent Issuer 

Issuer 

Subsidiaries 

Reclassifications 

and 

Eliminations 

Gastar 

Exploration Ltd. 

and 

Subsidiaries 

 (in thousands) 

ASSETS 

CURRENT ASSETS: 

Cash and cash equivalents $ 39 $ 25 $ 6,089 $ — $ 6,153 

Accounts receivable, net 2 — 5,294 — 5,296 

Commodity derivative contracts — 15 9,814 — 9,829 

Due from related parties — — 2,382 — 2,382 

Prepaid expenses 245 84 550 — 879 

 

Total current assets 286 124 24,129 — 24,539 

PROPERTY, PLANT AND EQUIPMENT: 

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

Unproved properties, not being amortized — 30,832 111,028 — 141,860 

Proved properties 8 51,132 257,963 — 309,103 

 

Total natural gas and oil properties 8 81,964 368,991 — 450,963 

Furniture and equipment — 49 948 — 997 

 

Total property, plant and equipment 8 82,013 369,939 — 451,960 

Accumulated depreciation, depletion and amortization (7 ) (44,412 ) (155,014 ) — (199,433 ) 

 

Total property, plant and equipment, net 1 37,601 214,925 — 252,527 

OTHER ASSETS: 

Restricted cash 25 — 45 — 70 

Deferred charges, net 433 6,416 — — 6,849 

Drilling advances — — 4,352 — 4,352 

Intercompany receivable and investment in subsidiaries 132,666 192,012 — (324,678 ) — 

Other assets — 100 — — 100 

 

Total other assets 133,124 198,528 4,397 (324,678 ) 11,371 

 

TOTAL ASSETS $ 133,411 $ 236,253 $ 243,451 $ (324,678 ) $ 288,437 

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND SHAREHOLDERS’ EQUITY 

CURRENT LIABILITIES: 

Accounts payable $ 9 $ — $ 14,247 $ $ 14,256 

Revenue payable — — 5,005 — 5,005 

Accrued interest 401 1,104 — — 1,505 

Accrued drilling and operating costs — 471 2,444 — 2,915 

Commodity derivative contracts — 78 1,043 — 1,121 

Other accrued liabilities 60 13 3,058 — 3,131 

Due to related parties — — 2,143 — 2,143 

Current portion of long-term debt 33,226 118,458 — — 151,684 

 

Total current liabilities 33,696 120,124 27,940 — 181,760 

LONG-TERM LIABILITIES: 

Asset retirement obligation 6 2,621 2,468 — 5,095 

Intercompany payable — 2,379 19,752 (22,131 ) — 

 

Total long-term liabilities 6 5,000 22,220 (22,131 ) 5,095 

TOTAL SHAREHOLDERS’ EQUITY 99,709 111,129 193,291 (302,547 ) 101,582 

 

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $ 133,411 $ 236,253 $ 243,451 $ (324,678 ) $ 288,437 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

Condensed Consolidating Parent and Issuer Subsidiaries Balance Sheets 

As of December 31, 2007 

 

 

F-45 

 Parent Issuer 

Issuer 

Subsidiaries 

Reclassifications 

and 

Eliminations 

Gastar 

Exploration Ltd. 

and 

Subsidiaries 

 (in thousands) 

ASSETS 

CURRENT ASSETS: 

Cash and cash equivalents $ 73 $ — $ 85,781 $ — $ 85,854 

Accounts receivable, net 10 265 5,188 (635 ) 4,828 

Due from related parties — — 904 — 904 

Prepaid expenses 291 — 944 — 1,235 

 

Total current assets 374 265 92,817 (635 ) 92,821 

PROPERTY, PLANT AND EQUIPMENT: 

Natural gas and oil properties, full cost method of

accounting: 

Unproved properties, not being amortized — 2,988 66,856 — 69,844 

Proved properties 8 43,611 203,753 — 247,372 

 

Total natural gas and oil properties 8 46,599 270,609 — 317,216 

Furniture and equipment — — 669 — 669 

 

Total property, plant and equipment 8 46,599 271,278 — 317,885 

Accumulated depreciation, depletion and amortization (7 ) (42,828 ) (117,930 ) — (160,765 ) 

 

Total property, plant and equipment, net 1 3,771 153,348 — 157,120 

OTHER ASSETS: 

Restricted cash 1,029 — 45 — 1,074 

Deferred charges, net 924 7,410 — — 8,334 

Drilling advances — — 2,251 — 2,251 

Intercompany receivable and investment in subsidiaries 128,677 209,494 — (338,171 ) — 

Other assets — 100 50 — 150 

 

Total other assets 130,630 217,004 2,346 (338,171 ) 11,809 

 

TOTAL ASSETS $ 131,005 $ 221,040 $ 248,511 $ (338,806 ) $ 261,750 

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND SHAREHOLDERS’ EQUITY 

CURRENT LIABILITIES: 

Accounts payable $ 47 $ — $ 11,954 $ — $ 12,001 

Revenue payable — — 6,770 — 6,770 

Accrued interest 401 1,133 — — 1,534 

Accrued drilling and operating costs — 350 2,460 — 2,810 

Commodity derivative contracts — 480 — — 480 

Other accrued liabilities 244 586 4,636 (635 ) 4,831 

Due to related parties — — 979 — 979 

 

Total current liabilities 692 2,549 26,799 (635 ) 29,405 

LONG-TERM LIABILITIES: 

Long-term debt 33,179 99,506 — — 132,685 

Asset retirement obligation 5 2,289 2,097 — 4,391 

Intercompany payable 589 1,615 26,668 (28,872 ) — 

 

Total long-term liabilities 33,773 103,410 28,765 (28,872 ) 137,076 

TOTAL SHAREHOLDERS’ EQUITY 96,540 115,081 192,947 (309,299 ) 95,269 

 

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $ 131,005 $ 221,040 $ 248,511 $ (338,806 ) $ 261,750 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

Condensed Consolidating Parent and Issuer Subsidiaries Statements of Operations 

For the Year Ended December 31, 2008 

 

 

F-46 

 Parent Issuer 

Issuer 

Subsidiaries 

Reclassifications 

and 

Eliminations 

Gastar 

Exploration Ltd. 

and 

Subsidiaries 

 (in thousands) 

REVENUES: 

Natural gas and oil revenues $ 1 $ 12,793 $ 43,896 $ — $ 56,690 

Unrealized natural gas hedge income — (63 ) 6,592 — 6,529 

 

Total revenues 1 12,730 50,488 — 63,219 

EXPENSES: 

Production taxes — 1,308 16 — 1,324 

Lease operating expenses — 3,051 4,516 — 7,567 

Transportation and treating — 2,000 2 — 2,002 

Depreciation, depletion and amortization — 716 23,735 — 24,451 

Impairment of natural gas and oil properties — 868 13,349 — 14,217 

Accretion of asset retirement obligation — 172 163 — 335 

General and administrative expenses 1,130 160 13,009 — 14,299 

 

Total expenses 1,130 8,275 54,790 — 64,195 

 

LOSS FROM OPERATIONS (1,129 ) 4,455 (4,302 ) — (976 ) 

OTHER (EXPENSES) INCOME: 

Interest expense (3,794 ) (2,092 ) 33 — (5,853 ) 

Investment income and other 54 (33 ) 1,521 — 1,542 

Equity earnings in subsidiaries (432 ) (2,762 ) — 3,194 — 

Foreign transaction loss (60 ) — (14 ) — (74 ) 

 

LOSS BEFORE INCOME TAXES (5,361 ) (432 ) (2,762 ) 3,194 (5,361 ) 

Provision for income taxes — — — — — 

 

NET LOSS $ (5,361 ) $ (432 ) $ (2,762 ) $ 3,194 $ (5,361 ) 

 

 

 

 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

Condensed Consolidating Parent and Issuer Subsidiaries Statements of Operations 

For the Year Ended December 31, 2007 

 

 

F-47 

 Parent Issuer 

Issuer 

Subsidiaries 

Reclassifications 

and 

Eliminations 

Gastar 

Exploration Ltd. 

and 

Subsidiaries 

 (in thousands) 

REVENUES $ 1 $ 7,076 $ 27,488 $ — $ 34,565 

EXPENSES: 

Production taxes — 752 13 — 765 

Lease operating expenses 2 2,870 3,412 — 6,284 

Transportation and treating — 1,641 — — 1,641 

Depreciation, depletion and amortization — 6,101 15,355 — 21,456 

Impairment of natural gas and oil properties — 1,141 27,373 — 28,514 

Accretion of asset retirement obligation — 155 126 — 281 

Mineral resource properties — — (133 ) — (133 ) 

General and administrative expenses 1,395 24 15,487 — 16,906 

Litigation settlement expense — — 1,365 — 1,365 

 

Total expenses 1,397 12,684 62,998 — 77,079 

 

LOSS FROM OPERATIONS (1,396 ) (5,608 ) (35,510 ) — (42,514 ) 

OTHER (EXPENSES) INCOME: 

Interest expense (13,817 ) (492 ) 230 — (14,079 ) 

Early extinguishment of debt (15,684 ) — — — (15,684 ) 

Investment income and other 20 — 3,176 — 3,196 

Equity earnings in subsidiaries 336 6,436 — (6,772 ) — 

Gain on sale of assets — — 38,536 — 38,536 

Foreign transaction gain 1 — 4 — 5 

 

INCOME (LOSS) BEFORE INCOME TAXES (30,540 ) 336 6,436 (6,772 ) (30,540 ) 

Provision for income taxes — — — — — 

 

NET INCOME (LOSS) $ (30,540 ) $ 336 $ 6,436 $ (6,772 ) $ (30,540 ) 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

Condensed Consolidating Parent and Issuer Subsidiaries Statements of Operations 

For the Year Ended December 31, 2006 

 

 

F-48 

 Parent Issuer 

Issuer 

Subsidiaries 

Reclassifications 

and 

Eliminations 

Gastar 

Exploration Ltd. 

and 

Subsidiaries 

 (in thousands) 

REVENUES $ 5 $ 9,107 $ 17,653 $ — $ 26,765 

EXPENSES: 

Production taxes — 1,096 382 — 1,478 

Lease operating expenses 7 2,581 2,961 — 5,549 

Transportation and treating — 1,557 — — 1,557 

Depreciation, depletion and amortization — 5,776 10,556 — 16,332 

Impairment of natural gas and oil properties — 15,718 40,562 — 56,280 

Accretion of asset retirement obligation — 151 83 — 234 

Mineral resource properties — 450 — 450 

General and administrative expenses 1,354 (416 ) 12,610 — 13,548 

Litigation settlement expense — 2,388 19 — 2,407 

 

Total expenses 1,361 28,851 67,623 — 97,835 

 

LOSS FROM OPERATIONS (1,356 ) (19,744 ) (49,970 ) — (71,070 ) 

OTHER (EXPENSES) INCOME: 

Interest expense (15,627 ) — 28 — (15,599 ) 

Investment income and other 1 83 1,752 — 1,836 

Equity loss in subsidiaries (67,852 ) (48,191 ) — 116,043 — 

Foreign transaction loss (5 ) (1 ) — (6 ) 

 

LOSS BEFORE INCOME TAXES (84,839 ) (67,852 ) (48,191 ) 116,043 (84,839 ) 

Provision for income taxes — — — — — 

 

NET LOSS $ (84,839 ) $ (67,852 ) $ (48,191 ) $ 116,043 $ (84,839 ) 

 

 

 

 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

Condensed Consolidating Parent and Issuer Subsidiaries Statements of Cash Flows 

For the Year Ended December 31, 2008 

 

 

F-49 

 Parent Issuer 

Issuer 

Subsidiaries 

Reclassifications 

and 

Eliminations 

Gastar 

Exploration Ltd. 

and 

Subsidiaries 

 (in thousands) 

CASH FLOWS FROM OPERATING ACTIVITIES: 

Net loss $ (5,361 ) $ (432 ) $ (2,762 ) $ 3,194 $ (5,361 ) 

Adjustments to reconcile net loss to net cash 

provided by (used in) operating activities: 

Depreciation, depletion and amortization — 716 23,735 — 24,451 

Impairment of natural gas and oil 

properties — 868 13,349 — 14,217 

Stock based compensation — — 3,129 — 3,129 

Unrealized natural gas hedge — 63 (6,592 ) — (6,529 ) 

Other comprehensive income portion of 

realized gas hedge — — 450 — 450 

Amortization of deferred financing costs 

and debt discount 538 1,460 — — 1,998 

Accretion of asset retirement obligation — 172 163 — 335 

Equity in earnings of issuer subsidiaries 432 2,762 — (3,194 ) — 

Changes in operating assets and liabilities, 

exclusive of effects of acquisition: 

Restricted cash for hedging program 1,000 — — — 1,000 

Accounts receivable 8 (370 ) (1,584 ) — (1,946 ) 

Prepaid expenses 46 (84 ) (184 ) — (222 ) 

Accounts payable and accrued 

liabilities (222 ) (23 ) 8,733 — 8,488 

 

Net cash provided by (used in) operating activities (3,559 ) 5,132 38,437 — 40,010 

 

CASH FLOWS FROM INVESTING ACTIVITIES: 

Development and purchases of natural gas and 

oil properties — (34,625 ) (95,862 ) — (130,487 ) 

Drilling advances — — (7,485 ) — (7,485 ) 

Purchase of furniture and equipment — (49 ) (279 ) — (328 ) 

Subsidiary equity (investment) payments 3,508 11,080 — (14,588 ) — 

Other — — 50 — 50 

 

Net cash used in investing activities 3,508 (23,594 ) (103,576 ) (14,588 ) (138,250 ) 

 

CASH FLOWS FROM FINANCING ACTIVITIES: 

Proceeds from revolving credit facility — 18,875 — — 18,875 

Subsidiary advances (payments) — — (14,588 ) 14,588 — 

Increase in restricted cash 4 — — — 4 

Deferred financing charges and other 13 (388 ) 35 — (340 ) 

 

Net cash provided by financing activities 17 18,487 (14,553 ) 14,588 18,539 

 

NET INCREASE (DECREASE) IN CASH AND 

CASH EQUIVALENTS (34 ) 25 (79,692 ) — (79,701 ) 

CASH AND CASH EQUIVALENTS, BEGINNING 

OF YEAR 73 — 85,781 — 85,854 

 

CASH AND CASH EQUIVALENTS, END OF YEAR $ 39 $ 25 $ 6,089 $ — $ 6,153 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

Condensed Consolidating Parent and Issuer Subsidiaries Statements of Cash Flows 

For the Year Ended December 31, 2007 

 

 

F-50 

 Parent Issuer 

Issuer 

Subsidiaries 

Reclassifications 

and 

Eliminations 

Gastar 

Exploration Ltd. 

and 

Subsidiaries 

 (in thousands) 

CASH FLOWS FROM OPERATING ACTIVITIES: 

Net income (loss) $ (30,540 ) $ 336 $ 6,436 $ (6,772 ) $ (30,540 ) 

Adjustments to reconcile net loss to net cash 

provided by (used in) operating activities: 

Depreciation, depletion and amortization — 6,101 15,355 — 21,456 

Impairment of natural gas and oil properties — 1,141 27,373 — 28,514 

Stock based compensation — — 3,948 — 3,948 

Amortization of deferred financing costs and 

debt discount 4,128 107 — — 4,235 

Accretion of asset retirement obligation — 155 126 — 281 

Gain on sale of assets — — (38,536 ) — (38,536 ) 

Loss on early extinguishment of debt 12,034 — — — 12,034 

Equity in earnings of issuer subsidiaries (336 ) (6,436 ) — 6,772 — 

Changes in operating assets and liabilities, 

exclusive of effects of acquisition: 

Restricted cash for hedging program (1,000 ) — — — (1,000 ) 

Accounts receivable (payable) (4 ) 223 7,215 (39 ) 7,395 

Prepaid expenses 9 135 (10 ) — 134 

Accounts payable and accrued liabilities 391 (573 ) (336 ) 39 (479 ) 

 

Net cash provided by (used in) operating activities (15,318 ) 1,189 21,571 — 7,442 

 

CASH FLOWS FROM INVESTING ACTIVITIES: 

Development and purchases of natural gas and oil 

properties (1 ) (4,432 ) (60,408 ) — (64,841 ) 

Proceeds from sale of natural gas and oil properties — — 66,513 — 66,513 

Drilling advances — — (5,070 ) — (5,070 ) 

Purchase of furniture and equipment — — (69 ) — (69 ) 

Subsidiary equity (investment) payments 66,197 (88,754 ) — 22,557 — 

 

Net cash provided by (used in) investing activities 66,196 (93,186 ) 966 22,557 (3,467 ) 

 

CASH FLOWS FROM FINANCING ACTIVITIES: 

Proceeds from the issuance of 12 3 / 4 % Senior 

Secured Notes — 99,500 — — 99,500 

Repayment of senior secured notes (73,000 ) — — — (73,000 ) 

Proceeds of issuance of common shares, net of share

issue costs 23,388 — — — 23,388 

Subsidiary advances — — 22,557 (22,557 ) — 

Increase in restricted cash (29 ) — — — (29 ) 

Deferred financing charges and other (1,210 ) (7,503 ) — — (8,713 ) 

 

Net cash provided by (used in) financing activities (50,851 ) 91,997 22,557 (22,557 ) 41,146 

 

NET INCREASE IN CASH AND CASH 

EQUIVALENTS 27 — 45,094 — 45,121 

CASH AND CASH EQUIVALENTS, BEGINNING OF 

YEAR 46 — 40,687 — 40,733 

 

CASH AND CASH EQUIVALENTS, END OF YEAR $ 73 $ — $ 85,781 $ — $ 85,854 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

Condensed Consolidating Parent and Issuer Subsidiaries Statements of Cash Flows 

For the Year Ended December 31, 2006 

 

 

F-51 

 Parent Issuer 

Issuer 

Subsidiaries 

Reclassifications 

and 

Eliminations 

Gastar 

Exploration Ltd. 

and 

Subsidiaries 

 (in thousands) 

CASH FLOWS FROM OPERATING ACTIVITIES: 

Net loss $ (84,839 ) $ (67,852 ) $ (48,191 ) $ 116,043 $ (84,839 ) 

Adjustments to reconcile net loss to net cash provided by 

(used in) operating activities: 

Depreciation, depletion and amortization — 5,776 10,556 — 16,332 

Impairment of natural gas and oil properties — 15,718 40,562 — 56,280 

Amortization of deferred lease costs — — 345 — 345 

Stock based compensation 11 — 3,898 — 3,909 

Amortization of deferred financing costs and debt 

discount 4,260 — — — 4,260 

Accretion of asset retirement obligation — 151 83 — 234 

Equity in loss of issuer subsidiaries 67,852 48,191 — (116,043 ) — 

Changes in operating assets and liabilities, 

exclusive of effects of acquisition: 

Accounts receivable (25 ) 4,124 (11,127 ) 674 (6,354 ) 

Prepaid expenses (129 ) (5 ) 316 — 182 

Accounts payable and accrued liabilities (2,482 ) 1,414 10,112 (674 ) 8,370 

 

Net cash provided by (used in) operating activities (15,352 ) 7,517 6,554 — (1,281 ) 

 

CASH FLOWS FROM INVESTING ACTIVITIES: 

Development and purchases of natural gas and oil 

properties 1 (7,105 ) (43,111 ) — (50,215 ) 

Purchase of natural gas and oil properties from related 

parties — (2,116 ) — (2,116 ) 

Drilling advances — — (14,228 ) — (14,228 ) 

Purchase of furniture and equipment — — (240 ) — (240 ) 

Subsidiary equity investment and payments (32,527 ) (551 ) — 33,078 — 

Other — (100 ) (50 ) — (150 ) 

 

Net cash used in investing activities (32,526 ) (7,756 ) (59,745 ) 33,078 (66,949 ) 

 

CASH FLOWS FROM FINANCING ACTIVITIES: 

Proceeds of issuance of common shares, net of share

issue costs 47,915 — — — 47,915 

Subsidiary advances — — 33,078 (33,078 ) — 

Increase in restricted cash — — (45 ) — (45 ) 

Deferred financing charges and other (16 ) — (35 ) — (51 ) 

 

Net cash provided by financing activities 47,899 — 32,998 (33,078 ) 47,819 

 

NET INCREASE (DECREASE) IN CASH AND CASH 

EQUIVALENTS 21 (239 ) (20,193 ) — (20,411 ) 

CASH AND CASH EQUIVALENTS, BEGINNING OF 

YEAR 25 239 60,880 — 61,144 

 

CASH AND CASH EQUIVALENTS, END OF YEAR $ 46 $ — $ 40,687 $ — $ 40,733 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

22. Supplemental Oil and Gas Disclosures—Unaudited 

The following disclosures for the Company are made in accordance with SFAS No. 69, “Disclosures About Oil and Gas Producing 

Activities”. 

Capitalized Costs Relating Oil and Producing Activities 

The following table presents the Company’s aggregate capitalized costs relating to oil producing activities and the related depreciation, 

depletion and amortization: 

 

Pursuant to SFAS No. 143, net capitalized cost includes related asset retirement cost of approximately $3.9 million, $3.6 million and $3.7 

million at December 31, 2008, 2007 and 2006, respectively. 

 

F-52 

 United States Australia Total 

 (in thousands) 

At December 31, 2008: 

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

Proved properties 308,499 604 309,103 

 

 427,222 23,741 450,963 

LESS 

Impairment of proved natural gas and oil properties (118,423 ) (604 ) (119,027 ) 

Accumulated depreciation, depletion and amortization (79,985 ) — (79,985 ) 

 

Total $ 228,814 $ 23,137 $ 251,951 

 

 

 

 

 

 

At December 31, 2007: 

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

Proved properties 246,768 604 247,372 

 

 293,295 23,921 317,216 

LESS 

Impairment of proved natural gas and oil properties (104,205 ) (604 ) (104,809 ) 

Accumulated depreciation, depletion and amortization (55,675 ) — (55,675 ) 

 

Total $ 133,415 $ 23,317 $ 156,732 

 

 

 

 

 

 

At December 31, 2006: 

Unproved properties $ 81,540 $ 8,118 $ 89,658 

Proved properties 180,758 604 181,362 

 

 262,298 8,722 271,020 

LESS: 

Impairment of proved natural gas and oil properties (75,691 ) (604 ) (76,295 ) 

Accumulated depreciation, depletion and amortization (34,348 ) — (34,348 ) 

 

Total $ 152,259 $ 8,118 $ 160,377 

 

 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities 

The following table sets forth costs incurred related to the Company’s natural gas and oil activities for the years ended December 31, 2008, 

2007 and 2006: 

 

The United States proved properties are expected to be developed over the next 5 years, while the Australian properties are anticipated to 

be developed over the next 10 years. 

 

F-53 

 United States Australia Total 

 (in thousands) 

For the year ended December 31, 2008: 

Unproved property acquisition $ 32,590 $ 8,835 $ 41,425 

Unproved property—GeoStar settlement 39,606 (9,015 ) 30,591 

Proved property—GeoStar settlement 882 — 882 

Exploration 26,050 — 26,050 

Development 34,799 — 34,799 

 

Total $ 133,927 $ (180 ) $ 133,747 

 

 

 

 

 

 

For the year ended December 31, 2007: 

Unproved property acquisition $ (7,036 ) $ 15,199 $ 8,163 

Unproved property divestment (27,977 ) — (27,977 ) 

Exploration 29,768 — 29,768 

Development 36,242 — 36,242 

 

Total $ 30,997 $ 15,199 $ 46,196 

 

 

 

 

 

 

For the year ended December 31, 2006: 

Unproved property acquisition $ 11,021 $ 4,618 $ 15,639 

Exploration 45,281 — 45,281 

Development 6,928 — 6,928 

 

Total $ 63,230 $ 4,618 $ 67,848 

 

 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

Results of Operations for Oil and Gas Producing Activities 

The following table sets forth results of operations for oil and gas producing activities for the years ended December 31, 2008, 2007 and 

2006: 

 

The results of producing activities exclude interest charges and general corporate expenses and represent United States activities only due 

to no producing operations activities in Australia to date. 

Net Proved and Proved Developed Reserve Summary 

The Company’s proved developed and proved undeveloped reserves are located only in the United States. The Company cautions that 

there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of 

development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. 

Accordingly, these estimates are expected to change as future information becomes available. Material revisions of reserve estimates may occur 

in the future; development and production of the oil and gas reserves may not occur in the periods assumed and actual prices realized and actual 

costs incurred may vary significantly from those used. Proved reserves represent estimated quantities of natural gas, crude oil and condensate 

that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under 

economic and operating conditions existing at the time the estimates were made. Proved developed reserves are proved reserves expected to be 

recovered through wells and equipment in place and under operating methods being utilized at the time the estimates were made. 

 

F-54 

 United States 

 

(in thousands, 

except per 

Mcfe data) 

For the year ended December 2008: 

Natural gas and oil sales, including unrealized natural gas hedge $ 63,219 

Production expenses (10,893 ) 

Impairment of natural gas and oil properties (14,217 ) 

Depreciation, depletion, and amortization (24,310 ) 

 

Results of producing activities $ 13,799 

 

 

Depreciation, depletion, and amortization rate per Mcfe $ 2.86 

 

 

For the year ended December 2007: 

Natural gas and oil sales $ 34,565 

Production expenses (8,690 ) 

Impairment of natural gas and oil properties (28,514 ) 

Depreciation, depletion, and amortization (21,327 ) 

 

Results of producing activities $ (23,966 ) 

 

 

Depreciation, depletion, and amortization rate per Mcfe $ 3.22 

 

 

For the year ended December 2006: 

Natural gas and oil sales $ 26,765 

Production expenses (8,584 ) 

Impairment of natural gas and oil properties (56,280 ) 

Depreciation, depletion and amortization (16,225 ) 

 

Results of producing activities $ (54,324 ) 

 

 

Depreciation, depletion, and amortization rate per Mcfe $ 3.44 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

The following table sets forth changes in estimated net proved and proved developed and undeveloped reserves for the years ended 

December 31, 2006, 2007 and 2008: 

 

The 2008 upward revision of previous estimates is primarily attributable to performance revisions in the Hilltop area of east Texas reduced 

by the impact of lower natural gas prices. Natural gas prices decreased approximately 25% from December 31, 2007 to December 31, 2008, 

resulting in a decrease in proved reserves of approximately 10,754 MMcf. The 2007 upward revision of previous estimates is primarily attributed 

to an increase in natural gas prices and performance revisions. An increase in natural gas prices of approximately 28% from 2006 resulted in an 

increase in 2007 proved reserves of approximately 3,815 MMcf, with the remaining 

 

F-55 

 Gas (MMcf) Oil (MBbl) 

Change in proved reserves 

Proved reserves as of December 31, 2005 33,023 1 

2006 Activity: 

Extensions and discoveries 11,120 — 

Revisions of previous estimates (8,340 ) 41 

Production (4,646 ) (12 ) 

 

Proved reserves as of December 31, 2006 31,157 30 

2007 Activity: 

Extensions and discoveries 24,064 — 

Revisions of previous estimates 6,178 (14 ) 

Production (6,577 ) (7 ) 

 

Proved reserves as of December 31, 2007 54,822 9 

2008 Activity: 

Extensions and discoveries 15,186 — 

Revisions of previous estimates 2,159 8 

Production (8,482 ) (5 ) 

 

Proved reserves as of December 31, 2008 63,685 12 

 

 

 

 

Proved Developed and Undeveloped Reserves 

December 31, 2006: 

Proved developed reserves 20,098 30 

Proved undeveloped reserves 11,059 — 

 

Total 31,157 30 

 

 

 

 

December 31, 2007: 

Proved developed reserves 34,058 9 

Proved undeveloped reserves 20,764 — 

 

Total 54,822 9 

 

 

 

 

December 31, 2008: 

Proved developed reserves 40,239 12 

Proved undeveloped reserves 23,446 — 

 

Total 63,685 12 

 

 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

portion of the increase attributable to upward performance revisions primarily in the Hilltop area of East Texas. The 2006 downward revision of 

previous estimates is primarily attributed to a decrease in natural gas prices and performance revisions in our Powder River Basin reserves in 

Wyoming. A decline in natural gas prices of approximately 36% from 2005 resulted in a decrease in proved reserves of approximately 4,836 

MMcf. The remaining proved reserve revision of previous estimates is attributed to downward revisions in the Powder River Basin based on 

updated well performance and reservoir pressure data, which was partially offset by upward performance revisions in the Hilltop area of East 

Texas. 

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves 

The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on natural gas and crude oil 

reserve and production volumes estimated by the independent petroleum reservoir engineers. This information may be useful for certain 

comparison purposes but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the 

following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of 

discounted future net cash flows be viewed as representative of the current value of the Company’s oil and gas assets. 

The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence at year end. It is 

expected that material revisions to some estimates of natural gas and crude oil reserves may occur in the future, development and production of 

the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. 

Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current 

laws, and which relate to oil and gas producing activities. Operating loss carryforwards to the extent estimated to be available in the future were 

also considered, thereby reducing expected tax expense. 

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a 

wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more 

representative of a range of possible economic conditions that may be anticipated. 

 

F-56 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

The Standardized Measure of Discounted Future Net Cash Flows relating to proved oil and gas reserves is presented below: 

 

 

F-57 

 United States 

 (in thousands) 

December 31, 2006: 

Future cash inflows $ 150,062 

Future production costs (57,726 ) 

Future development costs (36,629 ) 

Future income taxes — 

 

Future net cash flows 55,707 

10% annual discount for estimated timing of cash flows (15,369 ) 

 

Standardized measure of discounted future cash flows $ 40,338 

 

 

December 31, 2007: 

Future cash inflows $ 334,071 

Future production costs (82,466 ) 

Future development costs (58,857 ) 

Future income taxes — 

 

Future net cash flows 192,748 

10% annual discount for estimated timing of cash flows (60,516 ) 

 

Standardized measure of discounted future cash flows $ 132,232 

 

 

December 31, 2008: 

Future cash inflows $ 291,004 

Future production costs (72,265 ) 

Future development costs (51,274 ) 

Future income taxes — 

 

Future net cash flows 167,465 

10% annual discount for estimated timing of cash flows (57,376 ) 

 

Standardized measure of discounted future cash flows $ 110,089 

 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 

 

Changes in Standardized Measure of Discounted Future Net Cash Flows 

The principal sources of changes in the Standardized Measure of Future Net Cash Flows are as follows: 

 

 

F-58 

 United States 

 (in thousands) 

December 31, 2005 $ 91,295 

Extensions and discoveries, less related costs 22,403 

Sale of natural gas and oil, net of production costs (18,193 ) 

Revisions of previous quantity estimates (17,797 ) 

Net change in income tax — 

Net change in prices and production costs (63,106 ) 

Accretion of discount 9,130 

Development costs incurred 4,734 

Net change in estimated future development costs 10,840 

Change in production rates (timing) and other 1,032 

 

December 31, 2006 40,338 

Extensions and discoveries, less related costs 65,520 

Sale of natural gas and oil, net of production costs (25,875 ) 

Revisions of previous quantity estimates 19,800 

Net change in income tax — 

Net change in prices and production costs 29,576 

Accretion of discount 4,034 

Development costs incurred 10,075 

Net change in estimated future development costs (7,870 ) 

Change in production rates (timing) and other (3,366 ) 

 

December 31, 2007 132,232 

Extensions and discoveries, less related costs 22,634 

Sale of natural gas and oil, net of production costs (45,796 ) 

Revisions of previous quantity estimates 5,241 

Net change in income tax — 

Net change in prices and production costs (48,698 ) 

Accretion of discount 13,223 

Development costs incurred 20,056 

Net change in estimated future development costs 4,850 

Change in production rates (timing) and other 6,347 

 

December 31, 2008 $ 110,089 

 

 
Exhibit 10.31 

 

 

WAIVER UNDER CREDIT AGREEMENT 

among 

GASTAR EXPLORATION USA, INC. 

THE GUARANTORS SIGNATORY HERETO 

THE LENDERS SIGNATORY HERETO 

and 

AMEGY BANK NATIONAL ASSOCIATION, 

as Administrative Agent 

Effective 

March 12, 2009 

 

 

 
TABLE OF CONTENTS 

 

 

i 

Article I DEFINITIONS AND INTERPRETATION 1 

1.1 Terms Defined Above 1 

1.2 Terms Defined in Credit Agreement 2 

1.3 References 2 

1.4 Articles and Sections 2 

1.5 Number and Gender 2 

Article II WAIVER 2 

2.1 Waiver. 2 

2.2 Limitation on Waiver 3 

Article III REPRESENTATIONS AND WARRANTIES 3 

Article IV RATIFICATION AND ACKNOWLEDGMENTS 3 

Article V MISCELLANEOUS 4 

5.1 Successors and Assigns 4 

5.2 Rights of Third Parties 4 

5.3 Counterparts 4 

5.4 Integration 4 

5.5 Severability 4 

5.6 Governing Law 4 
WAIVER UNDER CREDIT AGREEMENT 

This WAIVER UNDER CREDIT AGREEMENT (this “ Waiver ”) executed effective as of March 12, 2009 (the “ Effective Date ”) is by 

and among GASTAR EXPLORATION USA, INC., a Michigan corporation (the “ Borrower ”), GASTAR EXPLORATION LTD., an Alberta, 

Canada corporation (the “ Parent ”), GASTAR EXPLORATION NEW SOUTH WALES, INC., a Michigan corporation (“ Gastar New South 

Wales ”), GASTAR EXPLORATION VICTORIA, INC., a Michigan corporation (“ Gastar Victoria ”), GASTAR EXPLORATION TEXAS, 

INC., a Michigan corporation (“ Gastar Texas Inc ”), GASTAR EXPLORATION TEXAS, LP, a Delaware limited partnership (“ Gastar Texas 

LP ”), and GASTAR EXPLORATION TEXAS LLC, a Delaware limited liability company (“ Gastar Texas LLC ”, and the Parent, Gastar New 

South Wales, Gastar Victoria, Gastar Texas Inc., Gastar Texas LP and Gastar Texas LLC, collectively, the “ Initial Guarantors ”), the lenders 

party to that certain Credit Agreement dated effective November 29, 2007 by and among the Borrower, the Initial Guarantors, the lenders party 

thereto or bound thereby from time to time (the “ Lenders ”), and Amegy Bank National Association, a national banking association, as 

administrative agent for the Lenders, letter of credit issuer and collateral agent for the Lenders and certain other parties (as amended to the 

Effective Date, the “ Credit Agreement ”), and AMEGY BANK NATIONAL ASSOCIATION, a national banking association, as administrative 

agent for the Lenders (in such capacity, the “ Agent ”). 

W I T N E S S E T H : 

WHEREAS, the Borrower, the Initial Guarantors, the Lenders and the Agent are parties to the Credit Agreement; and 

WHEREAS, the Borrower and the Initial Guarantors have requested that the Agent and the Lenders waive any default or right to exercise 

any remedy as a result of the inability of the Borrower and the Initial Guarantors to deliver to the Agent an unqualified opinion with respect to 

the consolidated Financial Statements of the Parent and its consolidated Subsidiaries at December 31, 2008 and for the year then ended, as 

required by Section 5.3 of the Credit Agreement, solely as a result of the pending maturities of the Obligations and the Parent’s convertible 

senior debentures due November 20, 2009; 

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained in the Credit Agreement and 

herein, the parties hereto agree as follows: 

ARTICLE I 

DEFINITIONS AND INTERPRETATION 

1.1 Terms Defined Above . As used in this Waiver Under Credit Agreement, each of the terms “ Agent ,” “ Borrower ,” “ Credit 

Agreement ,” “ Effective Date ,” “ Gastar New South Wales ,” “ Gastar Texas Inc ,” “ Gastar Texas LLC ,” “ Gastar Texas LP ,” “ Gastar 

Victoria ,” “ Initial Guarantors ,” Lenders ,” “ Parent ” and “ Waiver ” shall have the meaning assigned to such term hereinabove. 
1.2 Terms Defined in Credit Agreement . Each term defined in the Credit Agreement and used herein without definition shall have the 

meaning assigned to such term in the Credit Agreement, unless herein expressly provided to the contrary. 

1.3 References . References in this Waiver to Exhibit, Article or Section numbers shall be to Exhibits, Articles or Sections of this Waiver, 

unless expressly stated to the contrary. References in this Waiver to “hereby,” “herein,” “hereinafter,” “hereinabove,” “hereinbelow,” “hereof,” 

“hereunder” and words of similar import shall be to this Waiver in its entirety and not only to the particular Schedule, Exhibit, Article, or Section 

in which such reference appears. Specific enumeration herein shall not exclude the general and, in such regard, the terms “includes” and 

“including” used herein shall mean “includes, without limitation,” or “including, without limitation,” as the case may be, where appropriate. 

Except as otherwise indicated, references in this Waiver to statutes, sections, or regulations are to be construed as including all statutory or 

regulatory provisions consolidating, amending, replacing, succeeding, or supplementing the statute, section, or regulation referred to. References 

in this Waiver to “writing” include printing, typing, lithography, facsimile reproduction, and other means of reproducing words in a tangible 

visible form. References in this Waiver to amendments and other contractual instruments shall be deemed to include all exhibits and appendices 

attached thereto and all subsequent amendments and other modifications to such instruments, but only to the extent such amendments and other 

modifications are not prohibited by the terms of the Credit Agreement or this Waiver. References in this Waiver to Persons include their 

respective successors and permitted assigns. 

1.4 Articles and Sections . This Waiver, for convenience only, has been divided into Articles and Sections; and it is understood that the 

rights and other legal relations of the parties hereto shall be determined from this instrument as an entirety and without regard to the aforesaid 

division into Articles and Sections and without regard to headings prefixed to such Articles or Sections. 

1.5 Number and Gender . Whenever the context requires, reference herein made to the single number shall be understood to include the 

plural; and likewise, the plural shall be understood to include the singular. Definitions of terms defined in the singular or plural shall be equally 

applicable to the plural or singular, as the case may be, unless otherwise indicated. Words denoting sex shall be construed to include the 

masculine, feminine and neuter, when such construction is appropriate; and specific enumeration shall not exclude the general but shall be 

construed as cumulative. 

ARTICLE II 

WAIVER 

2.1 Waiver . 

(a) The Agent and the Lenders waive any Default or Event of Default under the Credit Agreement or any other Loan Document, 

together with the right of the Agent or the Lenders to exercise any remedy based thereon, as a result of, and agree that no breach of the 

Credit Agreement or any other Loan Document shall arise, including any 

 

- 2 -
breach of Section 5.3 of the Credit Agreement, as a result of, the audited Financial Statements of the Parent and its consolidated 

Subsidiaries for the fiscal year of the Parent ending on December 31, 2008, being accompanied by a qualified opinion of the Parent’s 

auditors, insofar and only insofar as such qualification is based on the Parent’s need to refinance or raise capital to retire debt maturing in 

2009 and any doubt raised thereby about the Parent’s ability to continue as a going concern. 

(b) The Agent and the Lenders waive any Default or Event of Default under the Credit Agreement or any other Loan Document, 

together with the right of the Agent or the Lenders to exercise any remedy based thereon, as a result of, and agree that no breach of the 

Credit Agreement or any other Loan Document shall arise, including any breach of Section 6.14 of the Credit Agreement, from, any failure 

of the ratio of Current Assets to Current Liabilities to be less than 1.00 to 1.00 determined as of the end of any quarter of the fiscal year of 

the Parent ending on December 31, 2009. 

2.2 Limitation on Waiver . Except for the waiver set forth above in Section 2.1 , nothing contained herein shall otherwise be deemed a 

consent to any violation of, or a waiver of compliance with, any term, provision or condition set forth in any of the Loan Documents or a consent 

to or waiver of any other or future violations, breaches, Defaults or Events of Default. 

ARTICLE III 

REPRESENTATIONS AND WARRANTIES 

Each of the Borrower and the Initial Guarantors expressly re-makes, in favor of the Agent and the Lenders, each of the representations and 

warranties set forth in Article IV of the Credit Agreement and in the other Loan Documents and made by it and represents and warrants that all 

such representations and warranties remain true and correct. 

ARTICLE IV 

RATIFICATION AND ACKNOWLEDGMENTS 

Each of the Borrower, the Initial Guarantors, the Lenders and the Agent does hereby adopt, ratify and confirm the Credit Agreement, as 

amended hereby, and each of the other Loan Documents to which it is a party and acknowledges and agrees that the Credit Agreement, as 

amended hereby, and each of the other Loan Documents to which it is a party is and remains in full force and effect. Furthermore, each of the 

Borrower, the Initial Guarantors, the Lenders and the Agent acknowledges and agrees that, as of the Effective Date, the Borrowing Base is 

$17,000,000 and the Monthly Reduction Amount is $1,000,000 (with the first reduction of such Borrowing Base amount by operation of such 

Monthly Reduction amount occurring on April 1, 2009), each of which shall remain at the relevant amount until redetermined in accordance with 

the provisions of Section 2.10 of the Credit Agreement; provided , however , it is agreed that, for a period of 60 days only following execution 

by the Borrower, the Parent or any of the other Initial Guarantors of a letter of intent or memorandum of understanding for the sale of assets of 

the Borrower, the Parent or any of the other Initial Guarantors for consideration (after payment of reasonable and customary costs of the 

transaction) sufficient to enable satisfaction of the 

 

- 3 -
condition to the extension of the Commitment Termination Date, pursuant to Section 2.6 of the Credit Agreement, set forth in clause (b) in the 

fourth sentence of Section 2.6 of the Credit Agreement, the Monthly Reduction Amount shall be $0 and that, upon the expiration of such 60 day 

period, the Monthly Reduction Amount shall again be $1,000,000. 

ARTICLE V 

MISCELLANEOUS 

5.1 Successors and Assigns . This Waiver shall be binding upon and inure to the benefit of the parties hereto and their respective 

successors and assigns permitted pursuant to the Credit Agreement. 

5.2 Rights of Third Parties . Except as provided in Section 5.1 , all provisions herein are imposed solely and exclusively for the benefit of 

the parties hereto. 

5.3 Counterparts . This Waiver may be executed by one or more of the parties hereto in any number of separate counterparts, and all of 

such counterparts taken together shall be deemed to constitute one and the same instrument and shall be enforceable as of the Effective Date 

upon the execution of one or more counterparts hereof by each of the parties hereto. In this regard, each of the parties hereto acknowledges that a 

counterpart of this Waiver containing a set of counterpart execution pages reflecting the execution of each party hereto shall be sufficient to 

reflect the execution of this Waiver by each necessary party hereto and shall constitute one instrument. 

5.4 Integration . This Waiver constitutes the entire agreement among the parties hereto with respect to the subject hereof. All prior 

understandings, statements and agreements, whether written or oral, relating to the subject hereof are superseded by this Waiver. 

5.5 Severability . In the event that any one or more of the provisions contained in this Waiver shall for any reason be held invalid, illegal or 

unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision of this Waiver. 

5.6 Governing Law . T HIS W AIVER SHALL BE DEEMED TO BE A CONTRACT MADE UNDER AND SHALL BE GOVERNED BY AND CONSTRUED IN 

ACCORDANCE WITH THE LAWS OF THE S TATE OF T EXAS , WITHOUT REGARD TO PRINCIPLES OF SUCH LAWS RELATING TO CONFLICTS OF LAW . 

(Signatures appear on following pages) 

 

- 4 -
IN WITNESS WHEREOF, the parties hereto have caused this Waiver under Credit Agreement to be duly executed and delivered, as of the 

Effective Date, by their proper and duly authorized officers. 

 

(Signatures continue on following pages) 

 

- 5 -

BORROWER : 

GASTAR EXPLORATION USA, INC. 

By: /s/ J. R USSELL P ORTER 

 J. Russell Porter 

 President 

INITIAL GUARANTORS : 

GASTAR EXPLORATION LTD. 

By: /s/ J. R USSELL P ORTER 

 J. Russell Porter 

 President and 

 Chief Executive Officer 

GASTAR EXPLORATION NEW SOUTH 

WALES, INC. 

By: /s/ J. R USSELL P ORTER 

 J. Russell Porter 

 President 
(Signatures continue on following page) 

 

- 6 -

GASTAR EXPLORATION VICTORIA, INC. 

By: /s/ J. R USSELL P ORTER 

 J. Russell Porter 

 President 

GASTAR EXPLORATION TEXAS, INC. 

By: /s/ J. R USSELL P ORTER 

 J. Russell Porter 

 President 

GASTAR EXPLORATION TEXAS, LP 

By: Gastar Exploration Texas LLC, 

 its General Partner 

 By: /s/ J. R USSELL P ORTER 

 J. Russell Porter 

 President 

GASTAR EXPLORATION TEXAS LLC 

By: /s/ J. R USSELL P ORTER 

 J. Russell Porter 

 President 
 

- 7 - 

AGENT : 

AMEGY BANK NATIONAL ASSOCIATION, 

as Agent 

By: / S / A. S TEPHEN K ENNEDY 

Name: A. Stephen Kennedy 

Title: Senior Vice President 

LENDER : 

AMEGY BANK NATIONAL ASSOCIATION 

By: / S / A. S TEPHEN K ENNEDY 

Name: A. Stephen Kennedy 

Title: Senior Vice President 
Exhibit 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 

 

 
TABLE OF CONTENTS 

 

 

i 

Article I DEFINITIONS AND INTERPRETATION 1 

1.1 Terms Defined Above 1 

1.2 Terms Defined in Credit Agreement 1 

1.3 References 1 

1.4 Articles and Sections 2 

1.5 Number and Gender 2 

Article II WAIVER 2 

2.1 Waiver 2 

2.2 Limitation on Waiver 2 

Article III REPRESENTATIONS AND WARRANTIES 2 

Article IV RATIFICATION AND ACKNOWLEDGMENTS 3 

Article V MISCELLANEOUS 3 

5.1 Successors and Assigns 3 

5.2 Rights of Third Parties 3 

5.3 Counterparts 3 

5.4 Integration 3 

5.5 Severability 3 

5.6 Governing Law 3 
WAIVER UNDER CREDIT AGREEMENT 

This WAIVER UNDER CREDIT AGREEMENT (this “ Waiver ”) executed effective as of March 13, 2009 (the “ Effective Date ”) is by 

and among GASTAR EXPLORATION USA, INC., a Michigan corporation (the “ Borrower ”), GASTAR EXPLORATION LTD., an Alberta, 

Canada corporation (the “ Parent ”), the lenders party to that certain Credit Agreement dated effective February 16, 2009 by and among the 

Borrower, the Parent, the lenders party thereto or bound thereby from time to time (the “ Lenders ”), and Wayzata Investment Partners LLC, as 

administrative agent for the Lenders (in such capacity, the “ Agent ”) (as amended to the Effective Date, the “ Credit Agreement ”). 

W I T N E S S E T H : 

WHEREAS, the Borrower, the Parent, the Lenders and the Agent are parties to the Credit Agreement; and 

WHEREAS, the Borrower and the Parent have requested that the Agent and the Lenders waive any default or right to exercise any remedy 

as a result of the inability of the Borrower and the Parent to meet the current ratio requirements as required by Section 7.14 of the Credit 

Agreement; 

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained in the Credit Agreement and 

herein, the parties hereto agree as follows: 

ARTICLE I 

DEFINITIONS AND INTERPRETATION 

1.1 Terms Defined Above . As used in this Waiver Under Credit Agreement, each of the terms “ Agent ,” “ Borrower ,” “ Credit 

Agreement ,” “ Effective Date ,” Lenders ,” “ Parent ” and “ Waiver ” shall have the meaning assigned to such term hereinabove. 

1.2 Terms Defined in Credit Agreement . Each term defined in the Credit Agreement and used herein without definition shall have the 

meaning assigned to such term in the Credit Agreement, unless herein expressly provided to the contrary. 

1.3 References . References in this Waiver to Exhibit, Article or Section numbers shall be to Exhibits, Articles or Sections of this Waiver, 

unless expressly stated to the contrary. References in this Waiver to “hereby,” “herein,” “hereinafter,” “hereinabove,” “hereinbelow,” “hereof,” 

“hereunder” and words of similar import shall be to this Waiver in its entirety and not only to the particular Schedule, Exhibit, Article, or Section 

in which such reference appears. Specific enumeration herein shall not exclude the general and, in such regard, the terms “includes” and 

“including” used herein shall mean “includes, without limitation,” or “including, without limitation,” as the case may be, where appropriate. 

Except as otherwise indicated, references in this Waiver to statutes, sections, or regulations are to be construed as including all statutory or 

regulatory provisions consolidating, amending, replacing, succeeding, or supplementing the statute, section, or regulation referred to. References 

in this Waiver to “writing” include printing, typing, lithography, facsimile reproduction, and other means of 
reproducing words in a tangible visible form. References in this Waiver to amendments and other contractual instruments shall be deemed to 

include all exhibits and appendices attached thereto and all subsequent amendments and other modifications to such instruments, but only to the 

extent such amendments and other modifications are not prohibited by the terms of the Credit Agreement or this Waiver. References in this 

Waiver to Persons include their respective successors and permitted assigns. 

1.4 Articles and Sections . This Waiver, for convenience only, has been divided into Articles and Sections; and it is understood that the 

rights and other legal relations of the parties hereto shall be determined from this instrument as an entirety and without regard to the aforesaid 

division into Articles and Sections and without regard to headings prefixed to such Articles or Sections. 

1.5 Number and Gender . Whenever the context requires, reference herein made to the single number shall be understood to include the 

plural; and likewise, the plural shall be understood to include the singular. Definitions of terms defined in the singular or plural shall be equally 

applicable to the plural or singular, as the case may be, unless otherwise indicated. Words denoting sex shall be construed to include the 

masculine, feminine and neuter, when such construction is appropriate; and specific enumeration shall not exclude the general but shall be 

construed as cumulative. 

ARTICLE II 

WAIVER 

2.1 Waivers . The Agent and the Lenders waive any Default or Event of Default under the Credit Agreement or any other Loan Document, 

together with the right of the Agent or the Lenders to exercise any remedy based thereon, as a result of, and agree that no breach of the Credit 

Agreement or any other Loan Document shall arise, including any breach of Section 7.14 of the Credit Agreement, from any failure of the ratio 

of Current Assets to Current Liabilities to be less than 1.00 to 1.00 determined as of the end of any quarter of the fiscal year of the Parent ending 

on December 31, 2009. 

2.2 Limitation on Waiver . Except for the waiver set forth above in Section 2.1 , nothing contained herein shall otherwise be deemed a 

consent to any violation of, or a waiver of compliance with, any term, provision or condition set forth in any of the Loan Documents or a consent 

to or waiver of any other or future violations, breaches, Defaults or Events of Default. 

ARTICLE III 

REPRESENTATIONS AND WARRANTIES 

Each of the Borrower and other Restricted Persons expressly re-makes, in favor of the Agent and the Lenders, each of the representations 

and warranties set forth in Article V of the Credit Agreement and in the other Loan Documents and made by it and represents and warrants that 

all such representations and warranties remain true and correct. 

 

- 2 -
ARTICLE IV 

RATIFICATION AND ACKNOWLEDGMENTS 

Each of the Borrower, the Parent, the Lenders and the Agent does hereby adopt, ratify and confirm the Credit Agreement, as amended 

hereby, and each of the other Loan Documents to which it is a party and acknowledges and agrees that the Credit Agreement, as amended 

hereby, and each of the other Loan Documents to which it is a party is and remains in full force and effect. 

ARTICLE V 

MISCELLANEOUS 

5.1 Successors and Assigns . This Waiver shall be binding upon and inure to the benefit of the parties hereto and their respective 

successors and assigns permitted pursuant to the Credit Agreement. 

5.2 Rights of Third Parties . Except as provided in Section 5.1 , all provisions herein are imposed solely and exclusively for the benefit of 

the parties hereto. 

5.3 Counterparts . This Waiver may be executed by one or more of the parties hereto in any number of separate counterparts, and all of 

such counterparts taken together shall be deemed to constitute one and the same instrument and shall be enforceable as of the Effective Date 

upon the execution of one or more counterparts hereof by each of the parties hereto. In this regard, each of the parties hereto acknowledges that a 

counterpart of this Waiver containing a set of counterpart execution pages reflecting the execution of each party hereto shall be sufficient to 

reflect the execution of this Waiver by each necessary party hereto and shall constitute one instrument. 

5.4 Integration . This Waiver constitutes the entire agreement among the parties hereto with respect to the subject hereof. All prior 

understandings, statements and agreements, whether written or oral, relating to the subject hereof are superseded by this Waiver. 

5.5 Severability . In the event that any one or more of the provisions contained in this Waiver shall for any reason be held invalid, illegal or 

unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision of this Waiver. 

5.6 Governing Law . T HIS W AIVER SHALL BE DEEMED TO BE A CONTRACT MADE UNDER AND SHALL BE GOVERNED BY AND CONSTRUED IN 

ACCORDANCE WITH THE LAWS OF THE S TATE OF M INNESOTA , WITHOUT REGARD TO PRINCIPLES OF SUCH LAWS RELATING TO CONFLICTS OF 

LAW . 

(Signatures appear on following pages) 

 

- 3 -
IN WITNESS WHEREOF, the parties hereto have caused this Waiver under Credit Agreement to be duly executed and delivered, as of the 

Effective Date, by their proper and duly authorized officers. 

 

 

(Signatures continue on following page) 

 

- 4 -

BORROWER : 

GASTAR EXPLORATION USA, INC. 

By: / S / M ICHAEL A. G ERLICH 

 Michael A. Gerlich 

 Secretary and Treasurer 

PARENT : 

GASTAR EXPLORATION LTD. 

By: / S / M ICHAEL A. G ERLICH 

 Michael A. Gerlich 

 Vice President and 

 Chief Financial Officer 
 

- 5 - 

AGENT : 

WAYZATA INVESTMENT PARTNERS LLC, 

as Agent 

By: / S / B LAKE C ARLSON 

 Blake Carlson 

 Authorized Signatory 

LENDER : 

WAYZATA OPPORTUNITIES FUND, LLC, 

as Lender 

By: 

 

Wayzata Investment Partners LLC, 

its Manager 

 By: / S / B LAKE C ARLSON 

 Blake Carlson 

 Authorized Signatory 

 
EXHIBIT 21.1 

GASTAR EXPLORATION LTD. 

Subsidiary List – December 31, 2008 

100% Subsidiaries owned of Gastar Exploration Ltd. (Alberta, Canada) 

Gastar Exploration USA, Inc. (Michigan) 

100% Subsidiaries owned of Gastar Exploration USA, Inc. (Michigan) 

Gastar Exploration New South Wales, Inc. (Michigan) 

Gastar Exploration Victoria, Inc. (Michigan) 

Gastar Exploration Texas LP (Delaware) (1)(2) 

Gastar Power Pty Ltd. (Australia) 

 

(1) Gastar Exploration Texas LLC (Delaware), General Partner (1%) 

(2) Gastar Exploration Texas, Inc. (Michigan), Limited Partner (99%) 
Exhibit 23.1 

Consent of Independent Registered Public Accounting Firm 

Gastar Exploration, Ltd. 

Houston, Texas 

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File Nos. 333-142123 and 

333-140397) and Form S-8 (File No. 333-130867) of Gastar Exploration, Ltd. of our reports dated March 13, 2009, relating to the consolidated 

financial statements and the effectiveness of Gastar Exploration Ltd.’s internal control over financial reporting, which appear in this Form 10-

K. Our report contains an explanatory paragraph regarding the Company’s ability to continue as a going concern. 

BDO Seidman, LLP 

Dallas, TX 

March 13, 2009 
Exhibit 23.2 

NETHERLAND, SEWELL & ASSOCIATES, INC. 

Gastar Exploration Ltd. 

1331 Lamar Street, Suite 1080 

Houston, Texas 77010 

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS 

Gentlemen: 

As independent oil and gas consultants, Netherland, Sewell & Associates, Inc. hereby consents to the incorporation by reference in the Annual 

Report on Form 10-K of Gastar Exploration Ltd. of information from our reserve report dated February 10, 2009 entitled “Estimate of Reserves 

and Future Revenues to Gastar Exploration Ltd. Interest in Certain Oil and Gas Properties located in the United States as of December 31, 2008, 

Based on Constant Prices and Costs in accordance with Securities and Exchange Commission Guidelines” and all references to our firm included 

in or made a part of the Gastar Exploration Ltd. Annual Report on Form 10-K for the year ended December 31, 2008. 

 

March 11, 2009 

Dallas, Texas 

Yours very truly, 

NETHERLAND, SEWELL & ASSOCIATES, INC. 

/s/ C.H. SCOTT REES 

C.H. (Scott) Rees III, P.E. 

President and Chief Operating Officer 
Exhibit 31.1 

CERTIFICATION OF CHIEF EXECUTIVE OFFICER 

PURSUANT TO 15 U.S.C. SECTION 7241, AS ADOPTED 

PURSUANT TO SECTION 302 OF THE 

SARBANES-OXLEY ACT OF 2002 

I, J. Russell Porter, certify that: 

 

 

 

 

 

 

 

 

 

 

 

Date: March 16, 2009 

 

1. I have reviewed this Quarterly Report on Form 10-K of Gastar Exploration, Ltd. (the “Registrant”); 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to 

make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period 

covered by this report; 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material 

respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report; 

4. The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as 

defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 

13a-15(f) and 15(d)-15(f)) for the Registrant and we have: 

 

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our 

supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to 

us by others within those entities, particularly during the period in which this report is being prepared; 

 

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designated 

under our supervision, 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; 

 

(c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about 

the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such 

evaluation; and 

 

(d) Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s 

most recent fiscal quarter (the Registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is 

reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and 

5. The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial 

reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent 

functions): 

 

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are 

reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and 

 

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s 

internal control over financial reporting. 

/s/ J. RUSSELL PORTER 

J. Russell Porter 

Chief Executive Officer 
Exhibit 31.2 

CERTIFICATION OF CHIEF FINANCIAL OFFICER 

PURSUANT TO 15 U.S.C. SECTION 7241, AS ADOPTED 

PURSUANT TO SECTION 302 OF THE 

SARBANES-OXLEY ACT OF 2002 

I, Michael A. Gerlich, certify that: 

 

 

 

 

 

 

 

 

 

 

 

Date: March 16, 2009 

 

1. I have reviewed this Quarterly Report on Form 10-K of Gastar Exploration, Ltd. (the “Registrant”); 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to 

make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period 

covered by this report; 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material 

respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report; 

4. The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as 

defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 

13a-15(f) and 15(d)-15(f)) for the Registrant and we have: 

 

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our 

supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to 

us by others within those entities, particularly during the period in which this report is being prepared; 

 

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designated 

under our supervision, 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; 

 

(c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about 

the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such 

evaluation; and 

 

(d) Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s 

most recent fiscal quarter (the Registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is 

reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and 

5. The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial 

reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent 

functions): 

 

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are 

reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and 

 

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s 

internal control over financial reporting. 

/s/ MICHAEL A. GERLICH 

Michael A. Gerlich 

Chief Financial Officer 
Exhibit 32.1 

Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 

I, J. Russell Porter, Chief Executive Officer of Gastar Exploration, Ltd. (the “Company”), hereby certify that the accompanying Annual 

Report on Form 10-K for 12 months ended December 31, 2008 (the “Report”), filed by the Company with the Securities and Exchange 

Commission on the date hereof pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 fully complies with the requirements 

of that section. 

I further certify that the information contained in the Report fairly presents, in all material respects, the financial condition and results of 

operations of the Company. 

Date: March 16, 2009 

 

/s/ J. RUSSELL PORTER 

J. Russell Porter 

Chief Executive Officer 
Exhibit 32.2 

Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 

I, Michael A. Gerlich, Chief Financial Officer of Gastar Exploration, Ltd. (the “Company”), hereby certify that the accompanying Annual 

Report on Form 10-K for 12 months ended December 31, 2008 (the “Report”), filed by the Company with the Securities and Exchange 

Commission on the date hereof pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 fully complies with the requirements 

of that section. 

I further certify that the information contained in the Report fairly presents, in all material respects, the financial condition and results of 

operations of the Company. 

Date: March 16, 2009 

 

/s/ MICHAEL A. GERLICH 

Michael A. Gerlich 

Chief Financial Officer