GASTAR EXPLORATION LTD

FORM 10-K

(Annual Report)

Filed 03/08/12 for the Period Ending 12/31/11

 

Address 1331 LAMAR STREET

SUITE 650

HOUSTON, TX 77010

Telephone 7137391800

CIK 0001170154

Symbol GST

SIC Code 1311 - Crude Petroleum and Natural Gas

Industry Oil & Gas Operations

Sector Energy

Fiscal Year 12/31

http://www.edgar-online.com

© Copyright 2012, 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 

OR 

 

GASTAR EXPLORATION LTD. 

GASTAR EXPLORATION USA, INC. 

(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. 

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. 

 

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. 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File 

 

FORM 10-K 

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

 For the Fiscal Year Ended December 31, 2011 

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

 For the transition period from to 

Commission File Number: 001-32714 

Commission File Number: 001-35211 

Alberta, Canada 98-0570897 

Delaware 38-3531640 

(State or other jurisdiction of 

incorporation or organization) 

(I.R.S. Employer 

Identification No.) 

1331 Lamar Street, Suite 650 

Houston, Texas 77010 

(Address of principal executive offices) (Zip Code) 

Gastar Exploration Ltd. Common Stock, No Par Value NYSE Amex, LLC 

Gastar Exploration USA, Inc. 8.625% Series A Cumulative Preferred Stock NYSE Amex, LLC 

(Title of Class) (Name of Exchange on which registered) 

Gastar Exploration Ltd. Yes  ̈ No ý 

Gastar Exploration USA, Inc. Yes  ̈ No ý 

Gastar Exploration Ltd. Yes  ̈ No ý 

Gastar Exploration USA, Inc. Yes  ̈ No ý 

Gastar Exploration Ltd. Yes ý No  ̈ 

Gastar Exploration USA, Inc. Yes ý No  ̈ 
required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such 

shorter period that the registrant was required to submit and post such files). 
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Index to Financial Statements 

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. 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). 

The aggregate market value of the voting and non-voting common equity of Gastar Exploration Ltd. held by non-affiliates of Gastar Exploration 

Ltd. as of June 30, 2011 (the last business day of Gastar Exploration Ltd.’s most recently completed second fiscal quarter) was approximately 

$193.9 million based on the closing price of $3.43 per share on the NYSE Amex, LLC. 

All common equity in Gastar Exploration USA, Inc. is held by Gastar Exploration Ltd., an affiliate of Gastar Exploration USA, Inc. 

Gastar Exploration USA, Inc. meets the conditions set forth in General Instruction (I)(1)(a) and (b) and is filing this Form with the reduced 

disclosure format. 

The total number of outstanding common shares, no par value per share, as of March 6, 2012 was: 

_____________________________________ 

Documents incorporated by reference: 

The information required by Part III of Form 10-K (Items 10, 11, 12, 13 and 14 thereunder) is incorporated by reference herein from portions of 

Gastar Exploration Ltd.'s definitive proxy statement relating to its 2012 annual meeting of shareholders to be filed with the U.S. Securities and 

Exchange Commission ("SEC") within 120 days of December 31, 2011. 

Gastar Exploration Ltd. Yes ý No  ̈ 

Gastar Exploration USA, Inc. Yes ý No  ̈ 

Gastar Exploration Ltd.  ̈ 

Gastar Exploration USA, Inc.  ̈ 

Gastar Exploration Ltd. Large accelerated filer  ̈ Accelerated filer ý 

 Non-accelerated filer  ̈ Smaller reporting company  ̈ 

Gastar Exploration USA, Inc. Large accelerated filer  ̈ Accelerated filer  ̈ 

 Non-accelerated filer ý Smaller reporting company  ̈ 

Gastar Exploration Ltd. Yes  ̈ No ý 

Gastar Exploration USA, Inc. Yes  ̈ No ý 

Gastar Exploration Ltd. 65,823,480 shares of common stock 

Gastar Exploration USA,Inc. 750 shares of common stock 

 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2011 

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 6 

 Competition 8 

 Seasonal Nature of Business 8 

 U.S. Governmental Regulation 8 

 Regulation of Exploration and Production 9 

 U.S. Environmental Regulation 11 

 Industry Segment and Geographic Information 15 

 Insurance Matters 15 

 Filings of Reserve Estimates with Other Agencies 15 

 Employees 15 

 Corporate Offices 15 

 Available Information 15 

 Item 1A. Risk Factors 16 

 Risks Related to Our Business 16 

 Risks Related to Our Common Shares 28 

 Item 1B. Unresolved Staff Comments 29 

 Item 2. Properties 29 

 Production, Prices and Operating Expenses 29 

 Drilling Activity 30 

 Exploration and Development Acreage 31 

 Undeveloped Acreage Expirations 31 

 Productive Wells 32 

 Natural Gas and Oil Reserves 32 

 Item 3. Legal Proceedings 36 

 Item 4. Mine Safety Disclosure 36 

PART II 

 

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

Securities 36 

 Market Information 36 

 Shareholders 36 

 Dividends 36 

 Recent Sales of Unregistered Securities; Use of Proceeds from Unregistered Securities 36 

 Item 6. Selected Financial Data 36 

 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 37 

 Overview 37 

 Financial Highlights 38 

 Results of Operations 39 

 Liquidity and Capital Resources 44 

 Off-Balance Sheet Arrangements 47 
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Index to Financial Statements 

 

 

ii 

 Page 

 Contractual Obligations 47 

 Commitments 47 

 Critical Accounting Policies and Estimates 48 

 Recent Accounting Developments 52 

 Item 7A. Quantitative and Qualitative Disclosures about Market Risk 52 

 Commodity Price Risk 52 

 Interest Rate Risk 52 

 Foreign Currency Exchange Risk 52 

 Item 8. Financial Statements and Supplementary Data 53 

 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 53 

 Item 9A. Controls and Procedures 53 

 Evaluation of Disclosure Controls and Procedures 53 

 Management’s Report on Internal Control over Financial Reporting 53 

 Changes in Internal Control over Financial Reporting 53 

 Report of Independent Registered Public Accounting Firm 55 

 Item 9B. Other Information 56 

PART III 

 Item 10. Directors and Executive Officers and Corporate Governance 56 

 Item 11. Executive Compensation 56 

 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 56 

 Item 13. Certain Relationships and Related Transactions and Director Independence 56 

 Item 14. Principal Accountant Fees and Services 56 

PART IV 

 Item 15. Exhibits, Financial Statements and Schedules 56 
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Index to Financial Statements 

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS 

This Annual Report on Form 10-K (“Form 10-K”) includes forward-looking information that is intended to be covered by the “forwardlooking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, 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"). All statements other 

than statements of historical fact included or incorporated by reference in this Form 10-K are forward-looking statements, including without 

limitation all statements regarding future plans, business objectives, strategies, expected future financial position or performance, expected future 

operational position or performance, budgets and projected costs, future competitive position or goals and/or projections of management for future 

operations. In some cases, you can identify a forward-looking statement by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,”

“project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target” or “continue,” the negative of such terms or 

variations thereon, or other comparable terminology. 

The forward-looking statements contained in this report are largely based on our expectations and beliefs concerning future developments and 

their potential effect on us, which reflect certain estimates and assumptions made by our management. These estimates and assumptions reflect our 

best judgment based on currently known market conditions, operating trends and other factors. Forward-looking statements may include statements 

that relate to, among other things, our: 

Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and 

uncertainties that are beyond our control. As such, management’s assumptions about future events may prove to be inaccurate. For a more detailed 

description of the risks and uncertainties involved, see Item 1A. “Risk Factors” in Part I of this Form 10-K. We do not intend to publicly update or 

revise any forward-looking statements as a result of new information, future events, changes in circumstances or otherwise. These cautionary 

statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. Management cautions all readers that the 

forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements 

will be realized or that the events and circumstances they describe will occur. Factors that could cause actual results to differ materially from those 

anticipated or implied in the forward-looking statements herein include, but are not limited to: 

iii 

• financial position; 

• business strategy and budgets; 

• anticipated capital expenditures; 

• drilling of wells, including the anticipated scheduling and results of such operations; 

• natural gas, oil and NGLs reserves; 

• timing and amount of future production of natural gas, oil, NGLs and condensate; 

• operating costs and other expenses; 

• cash flow and anticipated liquidity; 

• prospect development; and 

• property acquisitions and sales. 

• the supply and demand for natural gas, oil and NGLs; 

• low and/or declining prices for natural gas, oil and NGLs; 

• natural gas, oil and NGLs price volatility; 

• worldwide political and economic conditions and conditions in the energy market; 

• our ability to raise capital to fund capital expenditures or repay or refinance debt upon maturity; 

• the ability and willingness of our current or potential counterparties, third-party operators or vendors to enter into transactions with us 

and/or to fulfill their obligations to us; 

• failure of our joint interest partners to fund any or all of their portion of any capital program; 

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

• uncertainties about the estimated quantities of natural gas and oil reserves and in the projection of future rates of production and timing 

of development expenditures of proved reserves; 

• strength and financial resources of competitors; 

• availability and cost of material and equipment, such as drilling rigs and transportation pipelines; 
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Index to Financial Statements 

For a more detailed description of the risks and uncertainties that we face and other factors that could affect our financial performance or 

cause our actual results to differ materially from our projected results please see (i) Part I, Item 1A. “Risk Factors” and elsewhere in this Form 10-

K, (ii) our subsequent reports and registration statements filed from time to time with the Securities and Exchange Commission (“SEC”) and (iii) 

other announcements we make from time to time. 

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 update, revise or release any revisions to these forward-looking statements after 

the date on which they are made to reflect new information, events or circumstances occurring after the date of this Form 10-K or to reflect the 

occurrence of unanticipated events. 

Unless otherwise indicated or required by the context, (i) "Gastar," the "Company," "we," "us," "our" and similar terms refer collectively to 

Gastar Exploration Ltd. and its subsidiaries, including Gastar Exploration USA, Inc., and predecessors, (ii) "Gastar USA" refers to Gastar 

Exploration USA, Inc., our first-tier subsidiary and primary operating company, (iii) "Parent" refers solely to Gastar Exploration Ltd., (iv) all 

dollar amounts appearing in this Form 10-K are stated in United States dollars (“U.S. dollars”) unless otherwise noted and (v) all financial data 

included in this Form 10-K have been prepared in accordance with generally accepted accounting principles in the United States of America 

(“U.S. GAAP”). 

As of the opening of trading on August 3, 2009, a common share consolidation on the basis of one (1) common share for five (5) common 

shares (the “1-for-5 Reverse Split”) became effective. All common share and per share amounts reported in this Form 10-K have been reported 

on a post reverse split basis. 

iv 

• availability and cost of processing and transportation; 

• changes or advances in technology; 

• the risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry wells, operating hazards 

inherent to the natural gas and oil business and 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; 

• environmental risks; 

• possible new legislative initiatives and regulatory changes potentially adversely impacting our business and industry, including, but not 

limited to, national healthcare, hydraulic fracturing, state and federal corporate income taxes, retroactive royalty or production tax 

regimes, changes in environmental regulations, environmental risks and liability under federal, state and local environmental laws and 

regulations; 

• effects of the application of applicable laws and regulations, including changes in such regulations or the interpretation thereof; 

• potential losses from pending or possible future claims, litigation or enforcement actions; 

• potential defects in title to our properties or lease termination due to lack of activity or other disputes with mineral lease and royalty 

owners, whether regarding calculation and payment of royalties or otherwise; 

• the weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business; 

• ability to find and retain skilled personnel; and 

• any other factors that impact or could impact the exploration of natural gas or oil resources, including, but not limited to, the geology of 

a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and 

operational factors relating to the extraction of natural gas and oil. 
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Index to Financial Statements 

Glossary of Terms 

AMI Area of Mutual Interest, an agreed designated geographic area where joint venturers or other industry partners 

have a right of participation in acquisitions and operations 

Bbl Barrel of oil, condensate or NGLs 

Bbl/d Barrels of oil, condensate or NGLs per day 

Bcf One billion cubic feet of natural gas 

Bcfe One billion cubic feet of natural gas equivalent 

Btu British thermal unit, typically used in measuring natural gas energy content 

CBM Coal bed methane 

FASB Financial Accounting Standards Board 

GAAP Accounting principles generally accepted in the United States of America 

MBbl One thousand barrels of oil, condensate or NGLs 

MBbl/d One thousand barrels of oil, condensate or NGLs per day 

Mcf One thousand cubic feet of natural gas 

Mcf/d One thousand cubic feet of natural gas per day 

MMBtu/d One million British thermal units per day 

MMcf One million cubic feet of natural gas 

MMcf/d One million cubic feet of natural gas per day 

Mcfe One thousand cubic feet of natural gas equivalent 

MMcfe One million cubic feet of natural gas equivalent 

MMcfe/d One million cubic feet of natural gas equivalent per day 

NGLs Natural gas liquids 

psi Pounds per square inch 

 

v 
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Index to Financial Statements 

PART I 

Item 1. Business 

Overview 

We are an independent energy company engaged in the exploration, development and production of natural gas and oil in the U.S. Our 

principal business activities include the identification, acquisition, and subsequent exploration and development of natural gas and oil properties 

with an emphasis on unconventional reserves, such as shale resource plays. We are currently pursuing the development of liquids-rich natural gas in 

the Marcellus Shale in the Appalachia area of West Virginia and, to a lesser extent, central and southwestern Pennsylvania. We also hold 

prospective acreage in the deep Bossier play in the Hilltop area of East Texas and conduct limited CBM development activities within the Powder 

River Basin of Wyoming and Montana. 

Gastar Exploration Ltd. is a Canadian corporation, incorporated in Alberta in 1987 and subsisting under the Business Corporations Act 

(Alberta), with its common shares listed on the NYSE Amex under the symbol "GST." Gastar Exploration Ltd. is a holding company and 

substantially all of its operations are conducted through, and substantially all of its assets are held by, its primary operating subsidiary, Gastar USA 

and its wholly-owned subsidiaries. Gastar USA is a Delaware corporation with its 8.625% Series A Cumulative Preferred Stock listed on the NYSE 

Amex under the symbol "GST.PRA." Our principal office is located at 1331 Lamar Street, Suite 650, Houston, Texas 77010, and our telephone 

number is (713) 739-1800. Our website address is http://www.gastar.com . Information on our website or about us on any other website is not 

incorporated by reference into and does not constitute part of this Form 10-K. 

Our Strategy 

Our strategy is to increase stockholder value by delivering sustainable reserves growth and improved operating results from our existing 

assets. We recognize that there may be periods, such as the recent declines in natural gas prices, which make it difficult to fully execute this strategy

on a short-term basis. We intend to implement our strategy by focusing on: 

Continue Exploitation of Existing Marcellus Shale Assets and Focus on Areas with Relatively High NGLs and Condensate Content 

Due to lower natural gas prices, we are focusing the majority of our 2012 drilling activity in the liquids-rich area of the Marcellus Shale. Our 

2012 capital budget includes plans to drill and complete 20 gross (9.8 net) operated new Marcellus horizontal wells in Marshall County, West 

Virginia and complete 10 gross (4.5 net) additional operated Marcellus horizontal wells that were drilled and awaiting completion as of December 

31, 2011. In addition, during 2011, we increased our acreage position in Marcellus West (as defined below) to approximately 43,400 gross ( 19,900 

net) acres. We believe that the expansion of our acreage position and our drilling activity in the Marcellus Shale during 2011 has provided us with 

multi-year inventory of drilling opportunities in that area. Our focus continues to be in a prospectively liquids-rich area with subsequent focus on 

drilling acreage in order to hold the acreage "by production" prior to lease term expirations. 

 

Actively Manage Our Domestic Drilling Program 

We believe that operating approximately 87% of our drilling projects for 2012 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 the 

specialized skills needed to plan and execute the drilling and completion of horizontal Marcellus Shale wells. 

Manage and Utilize Technological Expertise 

We believe that 3-D seismic analysis, micro-seismic data acquisition and interpretation, 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 has helped us reduce drilling 

1 

• continued exploitation of existing Marcellus Shale assets with a focus on areas that we believe are prospective for natural gas with 

relatively high NGLs and condensate content; 

• active management of our domestic drilling program; and 

• effective management and utilization of technological expertise. 
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Index to Financial Statements 

risks, lower finding costs and provide for more efficient production of natural gas and oil from our properties. 

Natural Gas and Oil Activities 

The following provides an overview of our major natural gas and oil projects during 2011. 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. 

Marcellus Shale and Other Appalachia 

The Marcellus Shale is a Devonian aged formation that underlies much of the Appalachian region of Pennsylvania, New York, Ohio, West 

Virginia and adjacent states. The depth of the Marcellus Shale and its low permeability make the Marcellus Shale an unconventional exploration 

target in the Appalachian Basin. Advancements in horizontal drilling and stimulation have produced promising results in the Marcellus Shale. 

These developments have resulted in increased leasing and drilling activity in the area. At December 31, 2011, our acreage position in the 

Marcellus Shale was approximately 106,400 gross ( 76,100 net) acres. We refer to the approximately 43,400 gross ( 19,900 net) acres reflecting our 

interest in our Marcellus Shale assets in West Virginia and Pennsylvania subject to the Atinum Joint Venture described below as our Marcellus 

West acreage. We refer to the approximately 63,000 gross ( 56,200 net) acres in Preston, Tucker, Pocahontas, Randolph and Pendleton Counties, 

West Virginia as our Marcellus East acreage. The entirety of our acreage is believed to be in the core, over-pressured area of the Marcellus Shale 

play. 

On September 21, 2010, we entered into a joint venture (the "Atinum Joint Venture") pursuant to a purchase and sale agreement with Atinum 

Marcellus I, LLC ("Atinum"), an affiliate of Atinum Partners Co. Ltd., a Korean investment firm. Pursuant to the agreement, at the closing of the 

transaction on November 1, 2010, we assigned to Atinum, for $70.0 million in total consideration, an initial 21.43% interest in all of our existing 

Marcellus Shale assets in West Virginia and Pennsylvania, consisting of certain undeveloped acreage and a 50% working interest in 16 producing 

shallow conventional wells and one non-producing vertical Marcellus Shale well (the “Atinum Joint Venture Assets”). Atinum paid us 

approximately $30.0 million in cash upon closing. Additionally, Atinum is obligated to fund its 50% share of drilling, completion and infrastructure 

costs, and was obligated to pay an additional $40.0 million of future drilling costs in the form of a drilling carry obligation by funding 75% of our 

50% share of those same costs. As of December 31, 2011, Atinum had funded the entire $40.0 million drilling carry. Upon completion of the 

funding of the drilling carry, we made additional assignments, as necessary, to Atinum resulting in Atinum owning a 50% interest in the Atinum 

Joint Venture Assets. 

The Atinum Joint Venture's initial three-year development program called for the partners to drill a minimum of 12 horizontal wells in 2011, 

24 horizontal wells in 2012 and 24 horizontal wells in 2013. Due to recent natural gas price declines, Atinum and Gastar USA have agreed to 

reduce the 2012 minimum wells to be drilled requirement from 24 wells to 20 wells. As of December 31, 2011, we had drilled and cased 17 gross 

(7.2 net) operated wells and were in various stages of drilling on five gross (2.5 net) operated wells in Marshall County, West Virginia, under the 

Atinum Joint Venture. Through June 30, 2011, an initial AMI was established for potential additional acreage acquisitions in Ohio and New York 

along with the counties in West Virginia and Pennsylvania in which the existing Atinum Joint Venture Assets were located. Subsequent to June 30, 

2011, Atinum has the right to participate in any future leasehold acquisitions made by us within Ohio, New York, Pennsylvania and West Virginia, 

excluding the counties of Pendleton, Pocahontas, Preston, Randolph and Tucker, West Virginia, on terms identical to those governing the existing 

Atinum Joint Venture. We will act as operator and are obligated to offer any future lease acquisitions to Atinum on a 50/50 basis. Atinum will pay 

us on an annual basis an amount equal to 10% of lease bonuses and third party leasing costs up to $20.0 million and 5% of such costs on leasing 

activities above $20.0 million. 

In December 2010, we completed a Marcellus Shale leasehold acquisition for the Marcellus East acreage for an aggregate purchase price of 

$28.9 million. The acquisition consisted of undeveloped leasehold in the Marcellus Shale concentrated in Preston, Tucker, Pocahontas, Randolph 

and Pendleton Counties, West Virginia, including a gathering system comprised of 41 miles of four and six inch steel pipeline, a salt water disposal 

well and five conventional producing wells. Marcellus East was outside the initial AMI with Atinum, and Atinum elected not to acquire a 50% 

interest as provided under the terms of the Atinum Joint Venture. We believe their decision was due to the timing of the transaction and limited 

prior operational results within the initial Atinum Joint Venture AMI. We have completed the drilling of the Hickory Ridge 2H horizontal 

Marcellus well in Marcellus East in Preston County, West Virginia. We completed the 2,500 foot lateral with a ten-stage fracture stimulation in 

August 2011 and the well has recovered approximately 50% of the fluids used in its completion. Currently, the well is producing approximately 100 

Mcf/d. Nearby vertical wells also experienced low gas rates prior to recovering at least 75% of completion fluids. We recently installed a 

compressor to assist with accelerating the recovery of the completion fluids from the well, and we believe the well will be capable of of producing 

at economic rates. Due to the current natural gas price environment, we are currently not planning to drill any additional wells on the Marcellus East 

acreage during 2012, but we are 

2 
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Index to Financial Statements 

in the process of permitting a 3-D seismic survey over a portion of Marcellus East with a targeted completion date of early 2013. 

As of December 31, 2011, our operated well activity in Marshall County, West Virginia was comprised of nine gross (four net) producing 

wells, eight gross (3.2 net) wells drilled and either fracture stimulated or waiting to be fracture stimulated and five gross (2.5 net) wells in various 

stages of drilling in progress. The nine operated wells on production were comprised of the Wengerd 1H and 7H wells, the Corley 1H, 2H, 3H and 

4H wells and the Simms 1H, 2H and 3H wells. Subsequent to year end 2011, we placed the Hall 1H, 2H and 3H wells on sales resulting in total 

operated wells currently on sales of 12 gross (5.2 net) wells. Our average working interest in these 12 producing wells is 43.5% and the average 

well lateral length is approximately 4,900 feet. We are currently in the process of completing the fracture stimulation of the remaining two wells on 

the five well Hendrickson pad and anticipate having these five wells on sales by early April 2012. Our average working interest in the Hendrickson 

wells is 40% and the average well lateral length is approximately 4,700 feet. 

As of December 31, 2011, we had commenced drilling operations on the Burch Ridge lease, a five horizontal well pad scheduled for 

production in July 2012 and on the Accettolo lease, a three horizontal well pad scheduled for production in May 2012, in Marshall County, West 

Virginia. Our average working interest in the Burch Ridge and Accettolo wells is 50% and the average well lateral length for the Burch Ridge and 

Accettolo wells is targeted to be approximately 5,500 feet and 4,600 feet, respectively. 

As of December 31, 2011, we had participated on a non-operated basis in the drilling of seven horizontal Marcellus Shale wells in Butler 

County, Pennsylvania and an additional four non-operated horizontal Marcellus Shale wells in Marshall County, West Virginia. Three of the seven 

Butler County wells were turned to production on December 1, 2011 with the remaining four wells scheduled to be completed and on sales in 

March 2012. Our average working interest in the Butler County wells is 19.2% and the average lateral length of the wells is 3,900 feet. Of the four 

Marshall County non-operated wells, two of the wells were on production prior to year end and the remaining two wells are scheduled to be placed 

on production by late first quarter 2012. Our current average working interest in the Marshall County wells is 22.5% and the average well lateral 

length is approximately 4,200 feet. 

For the year ended December 31, 2011, net production from the Marcellus Shale averaged 2.4 MMcfe/d compared to 0.4 MMcfe/d in 2010, 

which was primarily from the shallower Devonian formation. For the three months ended December 31, 2011, net production from the Marcellus 

Shale averaged 5.2 MMcfe/d compared to 0.3 MMcfe/d for the three months ended December 31, 2010, which was primarily from the shallower 

Devonian formation. At December 31, 2011, proved reserves attributable to the Marcellus Shale were approximately 84.0 Bcfe, a significant 

increase from year-end 2010 reserves of 2.8 Bcfe. As of December 31, 2011, Marcellus Shale proved reserves represented approximately 70% of 

our total proved reserves. Total Marcellus Shale proved reserves at year-end 2011 were comprised of approximately 33% of oil and NGLs reserves 

compared to 7% at year-end 2010. Approximately 51% of the Marcellus Shale year-end 2011 reserves are proved developed. The following table 

provides production and operational information about the Marcellus Shale for the periods indicated: 

 

3 
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Index to Financial Statements 

_______________ 

For the fiscal year 2012, in Marshall County, West Virginia, we currently anticipate that we will drill and complete 20 gross (9.8 net) 

operated new horizontal Marcellus Shale wells and we will commence drilling operations on another nine gross (4.2 net) operated horizontal 

Marcellus Shale wells to be completed during 2013. Additionally, during 2012, we will complete 10 gross (4.5 net) operated horizontal Marcellus 

Shale wells that were drilled and awaiting completion as of December 31, 2011. Based on this projected activity, and assuming successful 

completion of wells budgeted for completion in 2012, we anticipate having 39 gross (18.0 net) operated wells on production by year-end 2012. 

Hilltop Area, East Texas 

At December 31, 2011, we held leases covering approximately 41,100 gross ( 21,900 net) acres in the Bossier play in the Hilltop area of East 

Texas in Leon and Robertson Counties. The Bossier play is an unconventional play characterized by Jurassic-age series of sands deposited in an 

ancient deepwater environment in mini-basins or depositional lows and on the flanks of structures that existed at the time of deposition. Wells in 

this area target multiple potentially productive natural gas formations and are typically characterized by high initial production and attractive longlived reserves per well. 

During 2011, we completed drilling of the Belin #2, an exploration well testing the deep Bossier formation in a separate fault block near the 

Belin #1 well. The well reached total depth of 19,650 feet and encountered approximately 130 net feet of pay in the lower Bossier formation within 

five separate sand intervals. The initial formation zone was fracture stimulated in April 2011 with marginal results. We are currently evaluating 

completion plans for this well. We have a 67% before payout working interest and an approximate 50% before payout net revenue interest in the 

Belin #2 well. 

We drilled the Belin #3 well in the same fault block as the Belin #2 well. The well reached total depth of 20,100 feet in mid-July 2011 and 

encountered approximately 60 net feet of pay in the lower Bossier formation within four separate sand intervals. The lower formation zones were 

fracture stimulated in September and October 2011. The lower zone initial 

4 

 For the Years Ended December 31, 

Marcellus Shale and Other Appalachia 2011 2010 2009 

Production: 

Natural gas (MMcf) 672 118 121 

Oil (MBbl) 11 2 2 

NGLs (MBbl) 21 — —

Total production (MMcfe) 860 133 135 

Natural gas (MMcf/d) 1.8 0.3 0.3 

Oil (MBbl/d) — — —

NGL (MBbl/d) 0.1 — —

Total daily production (MMcfe/d) 2.4 0.4 0.4 

Average sales price per unit: 

Natural gas per Mcf, excluding impact of realized hedging activities $ 3.43 $ 4.02 $ 4.02 

Natural gas per Mcf, including impact of realized hedging activities $ 3.43 $ 4.02 $ 4.02 

Oil (per Bbl) $ 71.37 $ 71.14 $ 55.14 

NGL (per Bbl) $ 52.47 $ — $ —

Selected operating expenses (in thousands): 

Production taxes $ 272 $ 30 $ 30 

Lease operating expenses $ 832 $ 393 $ 437 

Transportation, treating and gathering $ 85 $ 1 $ —

Selected operating expenses per Mcfe: 

Production taxes $ 0.32 $ 0.23 $ 0.23 

Lease operating expenses $ 0.97 $ 2.96 $ 3.25 

Transportation, treating and gathering $ 0.10 $ 0.01 $ —

Production costs (1) $ 1.03 $ 2.88 $ 3.15 

(1) Production costs include lease operating expense, insurance, gathering and workover expense and excludes ad valorem and severance taxes. 
Table of Contents 

Index to Financial Statements 

production rate was 1.9 MMcf/d, and the next zone fracture stimulation resulted in an initial production rate of 4.9 MMcf/d. The well is currently 

averaging approximately 0.8 MMcf/d. We will consider adding the two additional Bossier behind pipe zones at a later date. We have a 67% before 

payout working interest and an approximate 50% before payout net revenue interest in the Belin #3 well. 

We added two recompletion zones in the Wildman #5 during October 2011. Current production from the commingled zones in the well is 

approximately 2.3 MMcf/d. 

In May 2010, we drilled the Wildman 6H, a horizontal well, in the Glen Rose formation and completed it with a single- stage fracture 

stimulation. The Wildman 6H well was completed using a slotted liner which did not allow for the multi-stage fracture stimulation of the horizontal 

wellbore where several natural fractures were observed. Recognizing that our original completion approach was not optimal, we decided to further 

test the Glen Rose formation. Subsequently, we drilled two other wells to test the Glen Rose formation -- another horizontal well, the Wildman 8H, 

and a vertical well, the Williams #2. The Wildman 8H and Williams #2 were fracture stimulated and completed in late February 2011. While 

production results were initially encouraging, subsequent oil production has been lower than expected, primarily as a result of excessive water 

production. We will continue to monitor production for these wells before continuing with horizontal development of the Glen Rose formation. 

In January 2011, we attempted to test the Eagle Ford Shale/Woodbine formation with one well in East Texas, the Wildman 7H. The Wildman 

7H horizontal well was intended to test the Eagle Ford Shale/Woodbine formation, but due to drilling issues, the well was re-targeted and the 

horizontal lateral drilled in a slightly deeper transitional limestone zone known as the False Buda. The well was fracture stimulated with a 16-stage 

completion. Micro-seismic information was gathered during the completion process, and processing and interpretation of that data revealed that our 

fracture stimulation did not extend upward as anticipated in order to allow extraction from the Eagle Ford Shale/Woodbine formation. We 

postponed drilling a subsequent Eagle Ford well in 2012 as we monitor increasing offset operator drilling activity in the zone. If we drill an 

additional Eagle Ford/Woodbine Shale well, we expect the horizontal lateral will be targeted within the portion of the Eagle Ford Shale/Woodbine 

formation that was originally the target of the Wildman 7H well. 

5 
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Index to Financial Statements 

For the year ended December 31, 2011, net production from the Hilltop area averaged 17.3 MMcfe/d compared to 18.6 MMcfe/d for the year 

ended December 31, 2010. For the three months ended December 31, 2011, net production from the Hilltop area averaged approximately 15.5 

MMcfe/d compared to 23.8 MMcfe/d for the three months ended December 31, 2010. At December 31, 2011, proved reserves attributable to the 

Hilltop area were approximately 34.3 Bcfe, representing approximately 29% of our total proved reserves and of which 100% is proved developed. 

The following table provides production and operational information about the Hilltop area for the periods indicated: 

 

_______________ 

Due to the decline in natural gas prices, for fiscal year 2012, we currently plan to participate in the drilling of one gross (0.4 net) non-operated 

well in East Texas to test shallow oil potential in the Austin Chalk formation. 

Powder River Basin, Wyoming and Montana 

At December 31, 2011, we owned an average non-operated working interest of approximately 40% in approximately 35,900 gross ( 15,400 

net) acres within the Powder River Basin of Wyoming and Montana. We commenced drilling operations on eight gross (2.8 net) non-operated wells 

in 2011 to prevent lease termination. These wells are currently suspended awaiting completion operations. Drilling in 2012 is anticipated to 

continue to be limited due to continued weakness in natural gas prices in the area. As a result of the 2011 decrease in drilling activity and reduced 

compression, our Powder River Basin production averaged 1.4 MMcfe/d for the year ended December 31, 2011 down from 1.9 MMcfe/d in 2010. 

Markets and Customers 

The success of our operations is dependent primarily upon prevailing and future prices for natural gas, oil, NGLs and condensate. The 

markets for natural gas, oil and NGLs have historically been and currently continue to be volatile. Natural gas, 

6 

 For the Years Ended December 31, 

Hilltop Area, East Texas 2011 2010 2009 

Production: 

Natural gas (MMcf) 6,127 6,756 7,959 

Oil (MBbl) 30 8 2 

NGLs (MBbl) — 

Total production (MMcfe) 6,304 6,803 7,971 

Natural gas (MMcf/d) 16.8 18.5 21.8 

Oil (MBbl/d) 0.1 — —

NGL (MBbl/d) — — —

Total daily production (MMcfe/d) 17.3 18.6 21.8 

Average sales price per unit: 

Natural gas per Mcf, excluding impact of realized hedging activities $ 3.17 $ 3.49 $ 3.04 

Natural gas per Mcf, including impact of realized hedging activities $ 4.71 $ 4.05 $ 4.57 

Oil (per Bbl) $ 90.12 $ 73.10 $ 53.64 

NGL (per Bbl) $ — $ — $ —

Selected operating expenses (in thousands): 

Production taxes $ 153 $ 40 $ 35 

Lease operating expenses $ 5,863 $ 4,399 $ 4,023 

Transportation, treating and gathering $ 3,962 $ 4,038 $ 336 

Selected operating expenses per Mcfe: 

Production taxes $ 0.02 $ 0.01 $ —

Lease operating expenses $ 0.93 $ 0.65 $ 0.50 

Transportation, treating and gathering $ 0.63 $ 0.59 $ 0.04 

Production costs (1) $ 1.45 $ 1.14 $ 0.42 

(1) Production costs include lease operating expense, insurance, gathering and workover expense and excludes ad valorem and severance taxes. 
Table of Contents 

Index to Financial Statements 

oil and NGLs prices are beyond our control. 

We contract to sell natural gas from our properties with spot market contracts that vary with market forces on a daily basis. While overall 

natural gas prices at major markets, such as Henry Hub in Erath, 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. We do not own 

or operate any natural gas lines or distribution facilities and rely on third parties to construct additional interstate pipelines to increase our ability to 

bring our production to market. Any significant change affecting these facilities or our failure to obtain timely access to existing or future facilities

on acceptable terms could restrict our ability to conduct normal operations. Delays in the commencement of operations of new pipelines, the 

unavailability of new pipelines or other facilities due to market conditions, mechanical reasons or otherwise could have an adverse impact on our 

results of operations and financial condition. 

There are limited natural gas purchaser and transporter alternatives currently available in our Hilltop area of East Texas, where ETC Texas 

Pipeline, Ltd. (“ETC”) provides for the treating, purchase and transportation of substantially all of our natural gas production from this area. Our 

deep Bossier production is transported to the Katy Hub in Katy, Texas, where numerous parties are available to purchase our natural gas 

production. Our 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. 

Our oil, NGLs and condensate production in East Texas and the Appalachian Basin is sold under spot sales transactions at market prices. The 

availability and price responsiveness of the multiple oil and condensate purchasers provides for a highly competitive and liquid market for oil sales . 

During December 2010, we, along with Atinum, entered into a gas purchase agreement with SEI Energy, LLC (“SEI”) with respect to our 

Marshall County, West Virginia production. The initial term of the gas purchase agreement is five years with the option to extend the term of the 

gas purchase agreement for an additional five year period. Our Marshall County, West Virginia production is dedicated to SEI for the term of the 

gas purchase agreement. SEI will purchase all hydrocarbon production, including all natural gas, condensate and natural gas liquids. SEI has an 

agreement to utilize the new Caiman Energy Midstream, LLC ("Caiman") midstream facilities, including its 120.0 MMcf per day Fort Beeler 

processing plant located in Marshall County, West Virginia for transporting and processing. In order to secure access to the Caiman facilities, we, 

Atinum and SEI dedicated all hydrocarbons purchased and produced in Marshall County, West Virginia for a term of ten years. During 2011, our 

operated production and sales in West Virginia were impacted by issues with high line pressures on the Caiman gathering system. Caiman has 

subsequently corrected the majority of the high line pressure issues and reduced the impact of such on our production and sales in West Virginia. 

On November 16, 2009, concurrent with the sale of our Hilltop gathering system in East Texas, our wholly-owned subsidiary entered into a 

gas gathering agreement effective November 1, 2009 with Hilltop Resort GS, LLC (the “Hilltop Gathering Agreement”) for a term of 15 years. The 

Hilltop Gathering Agreement covers delivery of our gross production of natural gas in the Hilltop area of East Texas to certain delivery points 

provided under the ETC Contract as well as additional delivery points that, from time to time, may be added. We also are obligated to connect new 

wells that we drill within the area covered by the agreement to the gathering system. The Hilltop Gathering Agreement provides for a minimum 

quarterly gathering gross production volume of 50.0 MMcf per day (35.0 MMcf per day net to us) times the number of days in the quarter for five 

years from the effective date of November 1, 2009. If quarterly production is less than the minimum quarterly requirement, the gathering fee is 

payable on such deficit. If excess quarterly production exists, such excess is carried forward to offset any future deficit quarters. The gathering fee 

on the initial gross 25 Bcf of production is $0.325 per Mcf, reducing in steps to $0.225 per Mcf when cumulative gross production reaches 300 Bcf. 

In March 2008, we entered into formal agreements with ETC for the treating, purchase and transportation of substantially all of our natural 

gas production from the Hilltop area of East Texas (the “ETC Contract”). The ETC Contract was effective as of September 1, 2007 and has a term 

of 10 years. ETC currently provides us with 50.0 MMcf per day of treating capacity and 150.0 MMcf per day of transportation capacity of 

production from our wells located in Leon and Robertson Counties, Texas. 

The following table provides information regarding our significant customers and the percentages of natural gas, oil and NGLs revenues, 

excluding realized hedge impact, which they represented for the periods indicated: 

7 
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Index to Financial Statements 

ETC purchases substantially all of our East Texas natural gas production and Plains Marketing LP (“Plains”) purchases substantially all of our 

East Texas oil production. SEI purchases the majority of our Appalachian natural gas, oil and NGLs production and Enserco purchases substantially 

all of our Powder River Basin natural gas production. Management believes that the loss of either ETC, SEI, Plains or Enserco would not have a 

long-term material adverse impact on our financial position or results of operations, as there are other purchasers operating in the areas. 

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. Competition in the natural gas and oil exploration industry, 

however, 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. 

Seasonal Nature of Business 

Generally, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such 

as mild winters or abnormally hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage 

facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. 

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other natural gas and oil operations in certain 

areas. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which 

could lead to shortages, increase our costs or delay our operations. 

U.S. Governmental Regulation 

Our natural gas and oil exploration, production and related operations are subject to extensive rules and regulations promulgated in the United 

States. 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 governmental 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. 

8 

 For the Years Ended December 31, 

 2011 2010 2009 

ETC 69 % 86 % 85 % 

Enserco Energy, Inc. 6 % 9 % 13 % 

Plains Marketing LP 10 % 2 % —% 

SEI 8 % —% —% 
Table of Contents 

Index to Financial Statements 

The regulatory burden on the natural gas and oil industry increases our cost of doing business and affects our financial condition. Although 

we believe we are in substantial compliance with all applicable laws and regulations, we are unable to predict the future cost or impact of 

complying with such laws because those laws and regulations are frequently amended or reinterpreted. We are unable to predict what additional 

legislation or amendments may be proposed that will affect our operations or when any such proposals, if enacted, might become effective. We do 

not expect that any of these laws would affect us in a materially different manner than any other similarly sized natural gas and oil company 

operating in the United States. 

Regulation of Exploration and Production 

Regulation of Production 

The production of natural gas and oil is subject to extensive regulation under a wide range of federal, state and local statutes, rules, orders and 

regulations. Federal, state and local 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 some 

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. 

Regulation of Sales of Natural Gas 

The price at which we buy and sell natural gas is currently not subject to federal rate regulation and, for the most part, is not subject to state 

regulation. However, with regard to our physical purchases and sales of these energy commodities, and any related hedging activities that we 

undertake, we are required to observe anti-market manipulation laws and related regulations enforced by the Federal Energy Regulatory 

Commission (“FERC”) and/or the Commodity Futures Trading Commission (“CFTC”). See the discussion below of “Other Federal Laws and 

Regulations Affecting Our Industry – Energy Policy Act of 2005”. Should we violate the anti-market manipulation laws and regulations, we could 

also be subject to related third party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities. In 

addition, pursuant to Order 704 (defined below), we may be required to annually report to FERC on May 1 of each year information regarding 

natural gas purchase and sale transactions depending on the volume of natural gas transacted during the prior calendar year. See the discussion 

below of “Other Federal Laws and Regulations Affecting Our Industry – FERC Market Transparency Rules.” 

Regulation of Availability, Terms and Cost of Pipeline Transportation 

The availability, terms and cost of transportation can significantly affect sales of natural gas. FERC regulates interstate natural gas pipeline 

transportation rates and service conditions, which affect the marketing of natural gas produced by us and the revenues received by us for sales of 

such natural gas. FERC requires interstate pipelines to offer available firm transportation capacity on an open access, non-discriminatory basis to all 

natural gas shippers. FERC frequently reviews and modifies its regulations regarding the transportation of natural gas with the stated goal of 

fostering competition within all phases of the natural gas industry. In addition, with respect to production onshore or in state waters, the intra-state 

transportation of natural gas would be subject to state regulatory jurisdiction as well. 

The ability of our facilities to deliver natural gas into third party natural gas pipeline facilities is directly impacted by the gas quality 

specifications required by those pipelines. In 2006, FERC issued a policy statement on provisions governing gas quality and interchangeability in 

the tariffs of interstate gas pipeline companies and a separate order declining to set generic prescriptive national standards. FERC strongly 

encouraged all natural gas pipelines subject to its jurisdiction to adopt, as needed, gas quality and interchangeability standards in their FERC gas 

tariffs modeled on the interim guidelines issued by a group of industry representatives headed by the Natural Gas Council (the “NGC+ Work 

Group”), or to explain how and why their tariff provisions differ. We have no way to predict, however, whether FERC will approve of gas quality 

specifications that materially differ from the NGC+ Work Group’s interim guidelines for such an interconnecting pipeline. 

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. 

9 
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Index to Financial Statements 

Other Federal Laws and Regulations Affecting Our Industry 

Energy Policy Act of 2005. Under the Energy Policy Act of 2005 (the “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 2005 make it unlawful for any entity in connection with the purchase or sale of natural gas subject to the 

jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, 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. EPAct 2005 also gives the 

FERC authority to impose civil penalties for violations of the Natural Gas Act and the Natural Gas Policy Act up to $1,000,000 per day per 

violation. 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. 

FERC Market Transparency Rules. In 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as 

amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of 

physical natural gas in the previous calendar year including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas 

processors and natural gas marketers are now required to report on Form No. 552 on May 1 of each year aggregate volumes of natural gas 

purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of 

price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of 

Order 704. 

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot 

predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by 

any such FERC action materially differently than other natural gas companies with whom we compete. 

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 negotiated prices. Nevertheless, Congress could 

reenact price controls in the future. 

In a number of instances, however, the ability to transport and sell such products on interstate pipelines is dependent on pipelines whose rates, 

terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act (“ICA”). The ICA requires that pipelines 

maintain a tariff on file with FERC. The tariff sets forth the established rate as well as the rules and regulations governing the service. The ICA 

requires, among other things, that rates on interstate common carrier pipelines be “just and reasonable.” The ICA permits challenges to existing 

rates and authorizes FERC to investigate such rates to determine whether they are just and reasonable. If, upon completion of an investigation, 

FERC finds that the existing rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected 

during the pendency of the investigation and, in some cases, reparations for the two (2) year period prior to the filing of a complaint. We do not 

believe, however, that these regulations affect us any differently than other producers. 

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline 

regulation and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state. Insofar as effective 

interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not 

affect our operations in any way that is of material difference from those of our competitors who are similarly situated. 

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access 

standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When 

oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we 

believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors. 

10 
Table of Contents 

Index to Financial Statements 

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. 

U.S. Environmental Regulation 

Our natural gas and oil exploration and production operations, and similar operations that we do not operate but in which we own a working 

interest, are subject to stringent federal, regional, state and local environmental laws and regulations governing environmental protection as well as 

the discharge of substances into the environment. Environmental laws are implemented principally by the U.S. Environmental Protection Agency 

(“EPA”), the Department of Transportation, the Department of the Interior and other comparable state agencies. These laws and regulations may 

require that permits, including drilling permits, be obtained before conducting regulated activities; 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 

impose liabilities for pollution resulting from such operations; 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. 

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 capital 

expenditures or other 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 more significant existing environmental laws to which our business operations are subject. 

Hazardous Substances and Wastes 

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the Superfund law 

and analogous state laws impose strict, and, under certain circumstances, 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, these "responsible parties" 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. CERCLA also 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. 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 generate materials that are subject to regulation as hazardous substances under 

CERCLA. The scope of financial liability under CERCLA involves inherent uncertainties. 

The Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state laws regulate the 

11 
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Index to Financial Statements 

management, treatment, storage and disposal of hazardous and non-hazardous solid wastes. Our operations, and other operations in which we own 

an interest, generate wastes, including hazardous wastes that are subject to RCRA and comparable state laws. We believe that these operations are 

currently complying in all material respects with applicable RCRA requirements. Although RCRA currently exempts certain natural gas and oil 

exploration and production wastes from the definition of hazardous waste, we cannot assure that this exemption will be preserved in the future. For 

instance, in September 2010, the Natural Resource Defense Council filed a petition for rulemaking with the EPA requesting reconsideration of the 

continued application of this RCRA exclusion, but, to date, the EPA has not taken any action on the petition. Repeal or modification of this 

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 costs, 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 utilized operating and disposal practices that were standard in the industry at the 

time, 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 (including groundwater 

contamination) 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, as amended (“CWA”), as well as 

the Oil Pollution Act, as amended (“OPA”), and analogous state laws. These laws and their implementing regulations impose detailed requirements 

and strict controls regarding the discharge of pollutants, including spills and leaks of oil and other substances, into federal and state waters, 

including wetlands. In addition, depending on the location, discharges from or the withdrawal of water for use in our operations may be subject to 

regulation by regional or local regulatory authorities. Under the CWA and the OPA, any unauthorized release of pollutants from operations could 

cause us to become subject to the costs of remediating a release, including administrative, civil or criminal fines or penalties in addition to 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 

and implemented. 

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 regulation under the CWA, the Safe Drinking Water Act, as amended (“SDWA”), or an equivalent state 

regulatory program. Naturally occurring groundwater is also typically produced by coal bed methane ("CBM") production in our operations or in 

other operations in which we own an interest. This produced water is disposed of by injection into the subsurface through disposal wells permitted 

under the SDWA or an equivalent state regulatory program, discharge to surface water in compliance with permits issued by regulatory agencies 

pursuant to the CWA or an equivalent state program, or in evaporation ponds. To date, we believe that the produced water generated by our 

operations has been discharged or disposed of in substantial compliance with applicable environmental laws. Nonetheless, in connection with CBM 

production in the Powder River Basin, a concern of many operators in the Powder River 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. 

Hydraulic Fracturing 

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface 

rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture 

the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. 

Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant 

to the SDWA over certain hydraulic fracturing activities involving the use of diesel. In addition, legislation has been introduced before Congress to 

provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the 

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hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent 

permitting, disclosure, and well construction requirements on hydraulic fracturing activities. We believe that we follow applicable standard industry 

practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, 

state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially 

significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or 

production activities, and perhaps even be precluded from drilling wells. 

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing 

practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and 

a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has 

commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected 

to be available by late 2012 and final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of 

wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the 

U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or 

proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic 

fracturing under the federal SDWA or other regulatory mechanisms. Moreover, there have been public concerns expressed about naturally 

occurring radioactive materials being detected in flow back water resulting from hydraulic fracturing, particularly in the Marcellus Shale area. This 

concern could result in further regulation in the treatment, storage, handling and discharge of flow back water generated from these activities that, if 

implemented, could limit drilling or increase the costs of drilling in affected regions. To our knowledge, there have been no material citations, suits, 

or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect that are intended to 

provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance 

policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, 

the terms of such policies. 

Air Emissions 

The Clean Air Act, as amended (“CAA”), and comparable state laws and regulations govern emissions of various air pollutants through the 

issuance of permits and the imposition of other requirements. Air emissions from some equipment found at our operations or other operations in 

which we own an interest, such as gas compressors, are potentially subject to regulations under the CAA or equivalent state and local regulatory 

programs, although many small air emission sources are expressly exempt from such regulations. To the extent that these air emissions are 

regulated, they are generally regulated by permits issued by state regulatory agencies. To date, we believe that no unusual difficulties have been 

encountered in obtaining air permits. However, there is no assurance 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. For instance, in July 2011, the 

EPA proposed a range of new regulations that would establish new air emission controls for oil and natural gas production and natural gas 

processing, including, among other things, a new source performance standard for volatile organic compounds that would apply to hydraulically 

fractured wells, compressors, pneumatic controllers, condensate and crude oil storage tanks, and natural gas processing plants. The EPA is under a 

court order to finalize these proposed regulations by April 3, 2012. 

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. Particulate matter is also emitted as a result 

of our CBM production operations, generally in connection with construction activities and vehicle traffic but, to date, we do not believe that there 

has been any substantial difficulty in complying with regulatory or permitting requirements applicable to particulate matter. 

Climate Change 

In response to findings in December 2009 that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an 

endangerment to public health and the environment because emissions of such gases are contributing to the warming of the Earth’s atmosphere and 

other climatic changes, the EPA has adopted regulations under existing provisions of the CAA that require a reduction in emissions of GHGs from 

motor vehicles and also trigger construction and operating permit review for GHG emissions from certain stationary sources. The EPA has asserted 

that the final motor vehicle GHG 

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emission standards triggered Prevention of Significant Deterioration (“PSD”) and Title V permit requirements for stationary sources, commencing 

when the motor vehicle standards took effect on January 2, 2011. The EPA has published its final rule to address the permitting of GHG emissions 

from stationary sources under the PSD and Title V permitting programs, pursuant to which these permitting programs have been “tailored” to apply 

to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is anticipated that 

facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available 

control technology” standards for GHG. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air 

permits for new or modified facilities. In addition, the EPA adopted rules requiring the monitoring and reporting of GHGs from certain sources, 

including, among others, onshore and offshore oil and natural gas production facilities, which may include certain of our operations, on an annual 

basis. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring 

activities are in substantial compliance with applicable reporting obligations. In addition, Congress has actively considered legislation to reduce 

emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the 

planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations 

that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce 

emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce. Finally, it should 

be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that 

have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to 

occur, they could have an adverse effect on our exploration and production interests and operations. 

Endangered Species Act 

The federal Endangered Species Act, as amended (“ESA”), and similar state laws and other regulatory initiatives restrict 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. In these areas, we may be obligated to develop 

and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting operations in certain 

locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also 

possible that a federal or state agency could order a complete halt to our activities in certain locations if it is determined that such activities may 

have a serious adverse effect on a protected species. Moreover, as a result of a settlement approved by the U.S. District Court for the District of 

Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as 

endangered or threatened under the ESA over the next six years, through the agency's 2017 fiscal year. The presence of protected species or the 

designation of previously unidentified endangered or threatened species could impair our ability to timely complete well drilling and development 

and could cause us to incur additional costs arising from species protection measures or become subject to operating restrictions or bans in the 

affected areas. 

Operations on Federal Lands 

Performance of oil and gas exploration and production activities on federal lands, including Indian lands and lands administered by the 

federal Bureau of Land Management (“BLM”), may be subject to the National Environmental Policy Act, as amended (“NEPA”). NEPA requires 

federal agencies, including the BLM and the federal Bureau of Indian Affairs, to evaluate major agency actions, such as the issuance of permits that 

have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment 

that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed 

environmental impact statement that may be made available for public review and comment. Our current and proposed exploration and production 

activities upon federal lands require governmental permits that are subject to the requirements of NEPA. We are not planning any drilling 

operations on BLM leased acreage in 2012. Our future development of any project on BLM leased acreage will be subject to completion of these 

environmental assessments and any delays in such completion could result in delays in our exploration or production programs. Also, depending on 

the mitigation strategies recommended in the environmental assessments, we could incur added costs, which could be substantial. 

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 there from and are often 

based on negligence, trespass, nuisance, strict liability 

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or fraud. 

Industry Segment and Geographic Information 

We operate in one industry segment, which is the exploration, development and production of natural gas and oil. As a result of the sale of our 

Australian operations in July 2009, our current operational activities are conducted primarily in and our consolidated revenues are primarily 

generated from markets exclusively in the United States. 

Filings of Reserve Estimates with Other Agencies 

Previously, we filed with the Canadian System for Electronic Document Analysis and Retrieval (“SEDAR”) revised forms related to our oil 

and natural gas reserves. The forms provided additional information to ensure compliance with Canadian National Instrument 51-101, “Standards of 

Disclosure for Oil and Gas Activities” (“NI 51-101”), as required by the Alberta Securities Commission and the Toronto Stock Exchange. The 

filings did not affect any of our filings with SEC and were not considered part of our Form 10-K. The Form 51-101F1, “Statement of Reserves Data 

and Other Oil and Gas Information,” revised Form 51-101F2, “Report of Reserve Data by Independent Qualified Reserves Evaluator”, and revised 

Form 51-101F3, “Report of Management and Directors on Oil and Gas Disclosure” for the year ended December 31, 2010 were filed during 2011 

and can be found for viewing by electronic means on SEDAR at www.sedar.com . 

On December 16, 2011, the applicable provincial commissions in Canada issued a decision document which granted us exemptive relief from 

the disclosure requirements contained in NI 51-101. As a result, we are no longer required to comply with the requirements of NI 51-101 and 

accordingly, are not required to file Form 51-101F1, “Statement of Reserves Data and Other Oil and Gas Information,” revised Form 51-101F2, 

“Report of Reserve Data by Independent Qualified Reserves Evaluator,” and revised Form 51-101F3, “Report of Management and Directors on Oil 

and Gas Disclosure.” In lieu of such filings, we are permitted to provide disclosure with respect to our oil and gas activities in the form permitted 

by, and in accordance with, the legal requirements of the Securities Act, the Exchange Act and the rules and regulations of the SEC and the NYSE 

Amex. We are now required to file such disclosure on SEDAR as soon as practicable after such disclosure is filed with the SEC. 

Insurance Matters 

As is common in the oil and natural gas industry, we do not insure fully against all risks associated with our business either because such 

insurance may have been unavailable, because premium costs are considered not in line with our deemed exposure or the risk was deemed 

acceptable to self-insure. A loss not fully covered by insurance could have a materially adverse effect on our financial position, results of operations 

or cash flows. 

We maintain insurance at industry customary levels to limit our financial exposure in the event of a substantial environmental claim resulting 

from sudden, unanticipated and accidental discharges of certain prohibited substances into the environment. Such insurance might not cover the 

complete amount of such a claim and would not cover fines or penalties for a violation of an environmental law nor would it cover a gradual 

pollution loss. In analyzing our operations and insurance needs, and in recognition that we have a large number of individual well locations with 

varied geographical distribution, we compared premium costs to the likelihood of material loss of production. Based on this analysis, we have 

elected, at this time, not to carry loss of production or business interruption insurance for our operations. We carry limited property insurance. Our 

control of well limits are based upon our assessment of the risk and consideration of the cost of the insurance. 

Employees 

As of March 5, 2012, we had 42 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. 

Corporate Offices 

Our corporate office is located at 1331 Lamar Street, Suite 650, Houston, Texas 77010, where we lease 12,823 square feet. Additionally, we 

rent 6,375 square feet of office space in Clarksburg, West Virginia. 

Available Information 

Our website address is http://www.gastar.com . Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current 

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Index to Financial Statements 

reports on Form 8-K and any amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act are 

made available free of charge on our website as soon as reasonably practicable after we have electronically filed the material with or furnished it to 

the SEC. 

The public may also 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 . 

None of the information on our website should be considered incorporated into or a part of this Form 10-K. 

We also make available free of charge on our internet website at www.gastar.com under the “corporate governance” tab our: 

Item 1A. Risk Factors 

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 the oil and gas industry in which we operate. If any of the events described below occur, our business, financial 

condition, results of operations, liquidity or access to the capital markets could be materially adversely affected. There may be additional risks that 

are not presently material or known. 

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. 

Risks Related to Our Business 

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

With the exception of the one-time sale of our Australian properties in 2009, we have not been profitable since we started our business. 

Excluding after tax gains on the sale of assets, we incurred net losses of $ 1.8 million, $12.5 million and $92.4 million for the years ended 

December 31, 2011, 2010 and 2009, respectively. Our capital has been employed in an increasingly expanding natural gas and oil exploration and 

development program, with our focus on finding significant natural gas and oil reserves and producing from them over the long-term rather than 

focusing on achieving immediate net income. The uncertainties described in this “Item 1A – Risk Factors” and elsewhere in this Form 10-K 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 and continue our exploration and development program. 

Natural gas and oil prices are volatile and further declines in natural gas and oil prices would continue to significantly and negatively affect 

our financial condition and results of operations. Additionally, our results are subject to commodity price fluctuations related to seasonal and 

market conditions and reservoir and production risks. 

The success of our business depends primarily on the market prices of natural gas, oil and NGLs. Natural gas and oil commodity prices are set 

by broad market forces, which have been and will likely continue to be volatile in the future. For example, market prices for natural gas in the U.S. 

have declined substantially from 2008 price levels, and the rapid development of shale plays throughout North America has contributed 

significantly to this trend. Lower prices also may reduce the amount of natural gas or oil that we can produce economically. 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, oil or NGLs, market 

uncertainty and a variety of additional factors that are beyond our control. These factors include: 

16 

• Code of Ethics; 

• Corporate Governance Guidelines; 

• Audit Committee Charter; 

• Nominating and Governance Committee Charter: 

• Compensation Committee Charter; 

• Reserves Review Committee Charter; and 

• Whistleblower Procedure. 

• The domestic and foreign supply and demand of natural gas, oil and NGLs; 
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Index to Financial Statements 

The long-term effect of these and other factors on the prices of natural gas, oil and NGLs are uncertain. Prolonged or substantial declines in 

these commodity prices may have the following effects on our business: 

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. During 2011, 

approximately 80% of our production was priced based on the Katy Hub basis point, 7% was priced on the Colorado Interstate Gas (“CIG”) basis 

point and 9% was priced based on the Columbia Gas Appalachia Pool. Continued reduced prices for natural gas may compel us to limit our drilling 

operations in our Hilltop area to focusing on lease maintenance. CIG natural gas prices are volatile and historically have traded at significantly less 

than Henry Hub prices, primarily due to limitations in available pipeline capacity for natural gas deliveries out of the Rocky Mountain area. CIG 

natural gas prices may decline further if supplies of natural gas in the Rocky Mountains increase. Our West Virginia natural gas production is priced 

using the Columbia Gas Appalachia Pool. At December 31, 2011, the Henry Hub price was $ 4.12 per MMBtu, compared to our key basis point 

pricing of $ 4.07 per MMBtu at the Katy Hub, $ 3.93 per MMBtu for CIG and $ 4.20 per MMBtu for the Columbia Gas 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. 

The limited availability or high costs of hydraulic fracturing services in the Marcellus Shale and East Texas areas could adversely affect our 

ability to execute our exploration and development plans within our budget and on a timely basis. 

Our industry is cyclical and, from time to time, there is a shortage of materials, equipment, supplies and services, such as drilling rigs, fracture 

stimulation services and tubulars, well servicing equipment, gathering systems and transportation pipelines. During these periods, the costs and 

delivery times of those materials, equipment, supplies and services necessary to execute our drilling program are substantially greater. Shortages of 

fracturing equipment, water for hydraulic fracturing activities, and crews required for complex horizontal well completions in the Appalachia 

Marcellus Shale and East Texas deep Bossier and other zones could delay or adversely affect our development and exploration operations or cause 

us to incur significant expenditures that are not included in our capital budget. Delays could also have an adverse effect on our results of operations, 

including the timing of the initiation of production from new wells. See “—Federal and state legislation and regulatory initiatives relating to 

hydraulic fracturing could result in increased costs and additional operating restrictions or delays.” for a discussion of legislative and regulatory 

initiatives that could significantly restrict hydraulic fracturing and therefore make it more difficult or costly for us to perform hydraulic fracturing. 

Hedging of our production may result in losses or prevent us from benefiting to the fullest extent possible from increases in 

17 

• Volatile trading patterns in the commodity futures markets; 

• Overall economic conditions and market uncertainty;

• Weather conditions; 

• The cost of exploring for, developing, producing, transporting and marketing natural gas, oil and NGLs; 

• The proximity to, and capacity of, natural gas pipelines and other transportation facilities; 

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

• Domestic and foreign governmental regulations; and 

• The price and availability of competing alternative fuels. 

• Adversely affecting our financial condition, liquidity, ability to finance planned capital expenditures and results of operations; 

• Reducing the amount of natural gas, oil and NGLs that we can produce economically; 

• Causing us to delay or postpone some of our capital projects; 

• Reducing our revenues, operating income or cash flows; 

• Reducing the amounts of our estimated proved natural gas and oil reserves; 

• Reducing the carrying value of our natural gas and oil properties; 

• Reducing the standardized measure of discounted future net cash flows relating to natural gas and oil reserves; and 

• Limiting our access to sources of capital, such as equity and long-term debt. 
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Index to Financial Statements 

prices for natural gas and oil. 

We have entered into New York Mercantile Exchange (“NYMEX”) futures contracts as hedges on approximately 8.0 Bcf of natural gas 

production in 2012 and 4.7 Bcf in 2013 as of December 31, 2011. Although these hedges may partially protect us from 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. 

Our development operations will require substantial capital expenditures. 

The natural gas and oil industry is capital intensive. We make and expect to continue to make substantial growth capital expenditures in our 

business for the development, production and acquisition of natural gas and oil reserves. These expenditures will reduce the amount of cash 

available for distribution to our preferred stockholders. Our capital budget for 2012 totals $134.2 million, which we expect to fund these capital 

expenditures using cash generated from our operations, additional borrowings under our Revolving Credit Facility or the issuance of Series A 

Preferred Stock by Gastar USA, or some combination thereof. 

Our cash flows from operations and access to capital are subject to a number of variables, including: 

If the borrowing base under our credit facility or our revenues decrease as a result of lower natural gas or oil prices, operating difficulties, 

declines in estimated reserves or production or for any other reason, we may have limited ability to obtain the capital necessary to sustain our 

operations at current levels. If additional capital is needed to fund our growth capital expenditures, our ability to access the capital markets for 

future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our 

existing debt agreements, as well as by adverse market conditions resulting from, among other things, general economic conditions and 

contingencies and uncertainties that are beyond our control. 

Our failure to obtain the funds for necessary future growth capital expenditures could have a material adverse effect on our business, results 

of operations, financial condition and ability to pay distributions to our preferred stockholders. Even if we are successful in obtaining the necessary 

funds, the terms of such financings could limit our ability to pay distributions to our preferred stockholders. In addition, incurring additional debt 

may significantly increase our interest expense and financial leverage, and issuing additional preferred equity will increase the aggregate amount of 

cash required to make distributions to preferred stockholders. 

Approximately 50% of our proved reserves are classified as proved developed non-producing or proved undeveloped and may ultimately prove to 

be less than estimated. 

At December 31, 2011, approximately 50% of our total proved reserves were classified as proved developed non-producing or 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, 2011 assumes that we will spend significant development capital expenditures to develop these reserves, including an estimated 

$44.3 million and $6.1 million in 2012 and 2013, 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. 

Approximately 79% of our natural gas, oil and NGLs revenues before impact of realized hedges and 29% of our total proved reserves as of and 

for the year ended December 31, 2011 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. 

Our current production is geographically concentrated in East Texas. 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 

18 

• Our estimated proved natural gas and oil reserves; 

• The amount of natural gas, oil and NGLs that we produce from existing wells; 

• The prices at which we sell our production; 

• The costs of developing and producing our natural gas and oil production; 

• Our ability to acquire, locate and produce new reserves; 

• The ability and willingness of banks to lend to us; and 

• Our ability to access the capital markets. 
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Index to Financial Statements 

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 total East Texas production could reduce current revenues by an estimated $2.5 million to $3.9 million, before the impact of hedges, 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. 

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, 2011, 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. 

There are a limited number of natural gas purchasers and transporters in the Marcellus Shale in the Appalachia area of West Virginia and 

central and southwestern Pennsylvania. 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 purchasers and transporters in the Marcellus Shale in the Appalachia area of West Virginia and 

central and southwestern Pennsylvania. For the year ended December 31, 2011, SEI accounted for substantially all of our revenues from this area. If 

SEI were to cease purchasing and Caiman were to cease transporting our natural gas and we were unable to contract with another purchaser and/or 

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, oil and NGLs may be impaired by capacity constraints and availability of the gathering systems and 

pipelines that transport our natural gas and oil. 

The availability of a ready market for our natural gas, oil and NGLs production, particularly in the Appalachian area, depends on the 

proximity of our reserves to and the capacity of natural gas gathering systems, pipelines and trucking or terminal facilities. We do not own or 

operate any natural gas lines or distribution facilities and rely on third parties to construct additional interstate pipelines to increase our ability to 

bring our production to market. 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. 

There are a limited number of natural gas purchasers and transporters in the Marcellus Shale in the Appalachia area of West Virginia and 

central and southwestern Pennsylvania and in the Hilltop area in East Texas. For the year ended December 31, 2011, SEI accounted for 

substantially all of our revenues from the Marcellus Shale and ETC accounted for substantially all of our revenues from the Hilltop area in East 

Texas. If SEI were to cease purchasing and Caiman were to cease transporting our natural gas in the Marcellus Shale and if ETC were to cease 

purchasing and transporting our natural gas in the Hilltop area of East Texas and we were unable to contract with another purchaser and/or 

transporter, it would have a material adverse effect on our financial condition, future cash flows and the results of operations. 

Delays in the commencement of operations of new pipelines, the unavailability of the new pipelines or other facilities due to market 

conditions, mechanical reasons or otherwise could have an adverse impact on our results of operations and financial condition. Our Marcellus Shale 

production continues to be impacted by issues with high line pressures on the third-party operated gathering system. The operator of the gathering 

system anticipates having the line pressure issues alleviated by April 2012, but if they cannot be alleviated there may be further delays or 

curtailments in bringing our production to 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. 

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. Additionally, state regulators have 

powers over sale, supply and delivery of natural gas and oil within their state borders. While we 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. 

19 
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Index to Financial Statements 

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

Our future natural gas and oil production depends on our success in finding or acquiring new reserves. If we fail to replace reserves, our level 

of production and cash flows would be adversely impacted. Production from natural gas and oil properties decline as reserves are depleted, with the 

rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct 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, but not limited to: 

We use available seismic data to assist in the location of potential drilling sites. Even when properly used and interpreted, 2-D and 3-D 

seismic data and other visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon 

indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. Poor results from our 

drilling activities would have a material adverse effect on 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. 

Reserve estimates depend on many factors and assumptions, including various assumptions that are based on conditions in existence as of the 

dates of the estimates, which 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: 

20 

• Unexpected drilling conditions; 

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

• Pressure or irregularities in formations; 

• Environmental hazards, such as natural gas and oil leaks, pipeline or tank ruptures, and discharges of toxic gases or well fluids; 

• Uncontrollable flows of natural gas, oil, brine water or drilling fluids; 

• 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 or obtaining water for hydraulic fracturing 

operations. 

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

• Assumptions concerning the effects of regulations by governmental agencies; 

• Assumptions concerning future prices; 
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Index to Financial Statements 

Any of these variables or 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. For 2011, 2010 and 2009, the estimated discounted future net cash flows from proved reserves 

are based on the 12-month unweighted arithmetic average of the first-day-of-the-month prices and costs in effect when the estimate is made, and for 

2008, the estimated discounted future net cash flows from proved reserves are based on the December 31, 2008 spot price and costs in effect when 

the estimate was made. Current or actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be 

affected by factors such as: 

In this Form 10-K, the net present value of estimated future net revenues at December 31, 2011 is calculated using the 12-month unweighted 

arithmetic average of the first-day-of-the-month price and a 10% discount rate. This price and rate are not necessarily the most appropriate price or 

discount factor based on prices and interest rates in effect from time to time and risks associated with our reserves or the natural gas and oil industry

in general. 

Future downward revisions of the present value of our 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. We are subject to the full cost ceiling limitation 

which has resulted in past write-downs of estimated net reserves and may result in a write-down in the future if commodity prices continue to 

decline. 

Under the full cost method of accounting, we are subject to quarterly calculations of a “ceiling” or limitation on the amount of our oil and gas 

properties that can be capitalized on our balance sheet. We may experience write downs of the carrying value of our oil and gas properties in the 

future if the present value of our proved natural gas and oil reserves is lower than our remaining unamortized capitalized costs. If the net capitalized 

costs of our oil and gas properties exceed the cost ceiling, we are subject to a ceiling test write-down of our estimated net reserves to the extent of 

such excess. If required, it would reduce earnings and impact stockholders’ equity in the period of occurrence and result in lower amortization 

expense in future periods. The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the 

component that requires the most subjective judgments. The risk that we will be required to write down the carrying value of oil and natural gas 

properties increases when natural gas and crude oil prices are depressed or volatile. In addition, a write-down of proved oil and natural gas 

properties may occur if we experience substantial downward adjustments to our estimated proved reserves, if there are differences in timing 

between the incurrence of significant costs of exploration or development activities and the recognition of significant proved reserves resulting from 

such activities and if we experience unsuccessful drilling activities. Expense recorded in one period may not be reversed in a subsequent period 

even though higher natural gas and crude oil prices may have increased the ceiling applicable in the subsequent period. 

Our inability to meet a financial covenant contained in the Revolving Credit Facility may adversely affect our liquidity, financial condition or 

results of operations. 

We are subject to certain financial covenants which we are required to maintain under the Revolving Credit Facility (as defined herein) 

related to our working capital, cash flow and interest coverage ratio. If we breach a financial covenant and we are unable to cure such violation or 

obtain waivers from our lenders under the Revolving Credit Facility within the applicable 

21 

• 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; 

• 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. 
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Index to Financial Statements 

cure periods, such violation will constitute an event of default under the Revolving Credit Facility, and our lenders could terminate any 

commitments they have to make available further funds, accelerate the due dates for the payments of all outstanding indebtedness and exercise their 

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. 

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 affect 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. We cannot provide assurance that our counterparties will honor their obligations now or in the future. A 

counterparty’s insolvency or 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 counterparties were BP 

Corporation North America Inc. and Bank of Montreal. 

We are subject to various legal proceedings and claims. The cost of defending these lawsuits and any future lawsuits and any resulting 

judgments could be significant and could have a material adverse effect upon our financial condition. 

We are subject to various significant legal proceedings and claims arising outside of the normal course of business. No assurance can be given 

regarding the outcome of these legal proceedings, and additional claims may arise. We are vigorously defending the Company in these matters. This 

litigation, regardless of outcome or merit, however, can result in substantial costs and diversion of resources from our business. These costs would 

be reflected in terms of dollar outlay as well as the amount of time, attention and other resources that our management would have to appropriate to 

the defense of such claims. Considerable legal, accounting and other professional services expenses related to these matters have been incurred to 

date and significant expenditures may continue to be incurred in the future. Although we cannot predict the ultimate outcome of these matters or the 

liability that could potentially result, continuing defense costs and any adverse outcome could adversely affect our business, financial condition and 

results of operations. For more information on our significant currently outstanding legal proceedings, see Note 15, “Commitments and 

Contingencies Litigation”, to our consolidated financial statements included in this Form 10-K. 

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 operator’s 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. We currently are 

involved in a title litigation matter in East Texas. See Note 15, “Commitments and Contingencies – Litigation,” to our consolidated financial 

statements included in this Form 10-K. 

We are subject to stringent and complex laws and regulations, which may expose us to significant costs and liabilities and adversely affect the 

cost, manner or feasibility of conducting our business. 

Our natural gas and oil exploration and production interest and operations are subject to stringent and complex federal, state, provincial and 

local laws and regulations relating to the operation and maintenance of our facilities, including laws regulating removal of natural resources from 

the ground, the discharge of materials into the environment and otherwise relating to environmental protection. Natural gas and oil operations are 

also subject to federal, state, provincial and local laws and regulations which seek to maintain occupational health and safety standards by 

regulating the design and use of drilling methods and equipment. 

These government authorities require various permits, including drilling permits, before conducting regulated activities and we cannot assure 

you that such permits will be received. The failure or delay in obtaining the requisite approvals or permits 

22 
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Index to Financial Statements 

may adversely affect our business, financial condition and results of operations. Additionally, these laws and regulations impose numerous 

obligations and restrictions that are applicable to our interests and operations including, but not limited to: 

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 these laws and regulations applicable to our interests and operations could result in the assessment of administrative, 

civil and criminal penalties, the imposition of investigatory or remedial obligations and the issuance of orders enjoining or limiting some or all of 

our operations, any of which could have a material adverse effect on our financial condition. Legal requirements are sometimes unclear or subject to 

reinterpretation and may be amended in response to economic or political conditions. As a result, it is hard to predict the ultimate future cost of 

compliance with these requirements or their effect 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. 

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating 

restrictions or delays in the completion of natural gas and oil wells. 

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from 

tight formations such as shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the 

surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. The 

process is typically regulated by state oil and gas commissions, but the EPA recently asserted federal regulatory authority over hydraulic fracturing 

involving diesel under the SDWA’s Underground Injection Control Program, and has begun the process of drafting guidance documents on 

regulating requirements for companies that plan to conduct hydraulic fracturing using diesel. In addition, legislation has been introduced before 

Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic 

fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, 

disclosure, and well construction requirements on hydraulic fracturing activities. In the event that If new or more stringent federal, state, or local 

legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added 

costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and 

perhaps even be precluded from drilling wells. 

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing 

practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and 

a committee of the U.S. House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a 

study of the potential environmental effects of hydraulic fracturing activities, with initial results expected to be available by late 2012 and final 

results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic 

fracturing activities and plans to propose these standards by 2014. In addition, the U.S. Department of Energy and the U.S. Government 

Accountability Office are studying different aspects of how hydraulic fracturing might adversely affect the environment, and the U.S. Department 

of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal land, which, if adopted, would affect our 

operations on federal lands. These studies, depending on their results, could spur initiatives to regulate 

23 

• Drilling and abandonment bonds or other financial responsibility assurances; 

• Restriction on types, quantities and concentration of materials that can be released into the environment; 

• Reports concerning operations; 

• Spacing of wells; 

• Limits or prohibitions on drilling activities on certain lands lying within wilderness, wetlands and other protected areas; 

• The application of specific health and safety criteria addressing worker protection; 

• The imposition of substantial liabilities for pollution resulting from our operations; 

• Limitations on access to properties, particularly in the Powder River Basin; 

• Taxation; and 

• Other regulatory controls on operating activities. 
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Index to Financial Statements 

hydraulic fracturing under the SDWA or under newly established legislation. 

We could incur significant costs and liabilities in responding to contamination that occurs as a result of our operations. 

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations as a result of our 

handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to our operations, and due to historical 

industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to strict, joint and several 

liabilities for the removal or remediation of previously released materials or property contamination. Private parties, including the owners of 

properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, also 

may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and 

regulations or for personal injury or property or natural resource damages. Changes in environmental laws and regulations occur frequently, and any 

changes that result in more stringent or costly well drilling, construction, completion or water management activities, or waste control, handling, 

storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may 

otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. 

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: 

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. 

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a 

result of future legislation. 

President Obama’s budget proposal for the fiscal year 2012 recommended the elimination of certain key U.S. federal income tax preferences 

currently available to oil and gas exploration and production companies. These changes include, but are 

24 

• Well blowouts, fires and explosions; 

• Surface craterings and casing collapses; 

• Road collapses; 

• Uncontrollable flows of natural gas, oil, brine, water or well fluids; 

• Pipe and cement failures; 

• Formations with abnormal pressures; 

• Stuck drilling and service tools; 

• Pipeline or tank ruptures or spills; 

• Natural disasters; and 

• Environmental hazards, such as natural gas and oil leaks and discharge of toxic gases or well fluids. 

• Injury or death; 

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

• Damage to natural resources due to underground migration of hydraulic fracturing fluids; 

• Pollution and other environmental damage, including spillage or mishandling of recovered hydraulic fracturing fluids; 

• Regulatory investigations and penalties; 

• Suspension of operations; and 

• Repair and remediation costs. 
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Index to Financial Statements 

not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible 

drilling and development costs, (iii) the elimination of the deduction for U.S. production activities, and (iv) the increase in the amortization period 

from two years to seven years for geophysical costs paid or incurred in connection with the exploration for, or development of, oil or gas within the 

United States. 

It is unclear whether any such changes will actually be enacted or, if enacted, how soon any such changes could become effective. The 

passage of any legislation as a result of the budget proposal or any other similar change in U.S. federal income tax law could affect certain tax 

deductions that are currently available with respect to oil and gas exploration and production. 

Our natural gas and oil sales and our related hedging activities expose us to potential regulatory risks. 

The Federal Trade Commission, the FERC, and the CFTC hold statutory authority to monitor certain segments of the physical and futures 

energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to 

our physical sales of natural gas and oil and any related hedging activities that we undertake, we are required to observe the market-related 

regulations enforced by these agencies, which hold substantial enforcement authority. Our sales may also be subject to certain reporting and other 

requirements. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of 

operations, financial condition and our ability to make cash distributions to our unitholders. 

To the extent that we enter into transportation contracts with natural gas pipelines that are subject to FERC regulation, we are subject to 

FERC requirements related to use of such capacity. Any failure on our part to comply with the FERC’s regulations and policies, or with an 

interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties. 

The enactment of the Dodd – Frank Act could have an adverse impact on our ability to hedge risks associated with our business. 

Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter 

derivatives market and entities, including us, that participate in that market. The new legislation, known as the Dodd–Frank Wall Street Reform and 

Consumer Protection Act (the “Dodd–Frank Act”), was signed into law by the President on July 21, 2010 and requires CFTC and the SEC to 

promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the Dodd–

Frank Act, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for 

swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not 

possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may also require us to comply with 

margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the 

application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative 

instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The 

new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post 

collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of 

derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our 

exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of 

operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund 

capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators 

attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely 

affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse 

effect on us, our financial condition and our results of operations. 

Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the 

oil and natural gas we produce. 

In response to findings made by the EPA in December 2009 that emissions of GHGs present an endangerment to public health and the 

environment, the EPA has adopted regulations under existing provisions of the CAA that require a reduction in emissions of GHGs from motor 

vehicles and also that require certain construction and operating permit reviews for GHG emissions from certain stationary sources. The EPA rules 

addressing the permitting of GHG emissions from stationary sources under the Clean Air Act Prevention of Significant Deterioration ("PSD") 

construction and Title V operating permit programs have tailored the PSD and Title V permitting programs to apply to certain stationary sources of 

GHG emissions in a multi-step process, with the largest sources first subject to permitting. In addition, the EPA adopted rules requiring the 

monitoring and 

25 
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Index to Financial Statements 

reporting of GHGs from certain sources, including, among others, onshore and offshore oil and natural gas production facilities. Also, Congress 

has, from time to time, considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to 

reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. 

The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and 

operations could require us to incur significant added costs to reduce emissions of GHGs associated with our operations or could adversely affect 

demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of 

greenhouse gases in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and 

severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets 

and operations. 

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, wellestablished companies that have substantially larger operating staffs and greater capital resources than we do and, 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, 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. 

26 

• 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. 

• 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. 
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Index to Financial Statements 

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 effect 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. 

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. We do not operate these properties and have limited ability 

to exercise influence over operations for these properties. The success and timing of drilling, development and exploitation activities on properties 

operated by others depend on a number of factors that are beyond our control. Likewise, as a result of our dependence on the operator and other 

working interest owners for these projects, we are limited in our ability to drill wells to protect against drainage. Although there has not been a 

material number of offsetting wells drilled adjacent to our properties at this time, 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 and our ability to recognize proved reserves from this basin during periods of low natural gas 

prices. 

The shallow coal 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. The extended decline in gas prices through 2009 combined with the revised pricing methodology under the new SEC rules, 

described in more detail above, had a negative impact on our reserves in the Powder River Basin. As of December 31, 2011, we did not recognize 

any proved undeveloped reserves in the Powder River Basin, and we only recognized minimal proved undeveloped reserves as of December 31, 

2010. Our proved developed reserves in the Power River Basin had only nominal value at such dates. 

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. 

27 

• 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 

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

Two of our directors 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 U.S. courts any judgment obtained there against them 

predicated upon any civil liability provisions of the U.S. federal securities laws. Investors should not assume that Canadian courts will enforce 

judgments of U.S. courts obtained in actions against those directors predicated upon the civil liability provisions of the U.S. 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 U.S. federal securities laws or any such state securities or blue sky laws. 

Current and future economic conditions in the United States and key international markets may materially adversely impact our operating 

results. 

Our operations are affected by local, national and international economic conditions and the condition of the natural gas and oil industry. The 

United States and other world economies are slowly recovering from a recession, which began in 2008 and has extended into 2012. Although 

growth has resumed, it is modest and certain economic data indicates the United States and worldwide economies may require some time to 

recover. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic 

growth rate that is slower than what was experienced in recent years. In addition, more volatility may occur before a sustainable, yet lower, growth 

rate is achieved. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate 

will result in decreased demand growth for our natural gas production and crude oil, as well as lower commodity prices, which will reduce our cash 

flows from operations and our profitability. 

Continued market deterioration could also jeopardize the performance of certain counterparty obligations, including those of our insurers, 

customers and financial institutions. Although we assess the creditworthiness of our counterparties, prolonged business decline or disruptions as a 

result of economic slow-down or lower commodity prices could lead to changes in a counterparty’s liquidity and increase our exposure to credit 

risk and bad debts. In the event any such party fails to perform, our financial results could be adversely affected and we could incur losses and our 

liquidity could be negatively impacted. 

Risks Related to Our Common Shares 

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

The trading price of our common shares are subject to wide fluctuations in response to a variety of factors, including quarterly variations in 

operating results, announcements of drilling and rig activity, economic conditions in the natural gas and oil industry, general economic conditions 

or other events or factors that are beyond our control. 

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 certain natural gas and oil exploration 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 U.S., 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 Amex LLC or any future exchange on which our common 

28 
Table of Contents 

Index to Financial Statements 

shares might trade. The issuance of a large number of common shares could be effected by our directors to thwart a takeover attempt or offer for us 

by a third party, 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. 

We are able to issue shares of preferred stock with greater rights than our common shares. 

Our Amended and Restated Articles of Incorporation authorize our board of directors to issue one or more series of preferred shares and set 

the terms of the preferred shares without seeking any further approval from our shareholders. Any preferred shares that are issued may rank ahead 

of our common shares in terms of dividends, liquidation rights, or voting rights. If we issue preferred shares, it may adversely affect the market 

price of our common shares. 

Because we have no plans to pay dividends on our common shares, shareholders must look solely to appreciation of our common shares to 

realize a gain on their investment. 

We do not anticipate paying any dividends on our common shares in the foreseeable future. We currently intend to retain any future earnings 

to finance the expansion of our business. In addition, the Revolving Credit Facility contains covenants that prohibit us from paying cash dividends 

as long as such debt remains outstanding. The payment of future dividends, if any, will be determined by our board of directors in light of 

conditions then existing, including our earnings, financial condition, capital requirements, restrictions in financing agreements, business conditions 

and other factors. Accordingly, shareholders must look solely to appreciation of our common shares to realize a gain on their investment, which 

may not occur. 

Item 1B. Unresolved Staff Comments 

None. 

Item 2. Properties 

Our properties consist primarily of natural gas and oil leases in the following areas: 

Additional information concerning our interests and related natural gas and oil activities in these areas is described under “Item 1 – Business” 

of this Form 10-K. 

29 

• Marcellus Shale in West Virginia and central and southwestern Pennsylvania; 

• Hilltop area of East Texas; and 

• Powder River Basin in Wyoming and Montana. 
Table of Contents 

Index to Financial Statements 

Production, Prices and Operating Expenses 

The following table presents information regarding production volumes, average sales prices received and selected data per Mcfe associated 

with our sales of natural gas, oil and NGLs for the periods indicated. Oil, condensate and NGLs are compared with natural gas in terms of cubic feet 

of natural gas equivalents. One barrel of oil, condensate or NGLs 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” refers to wells in which we have a working 

interest, and “net” refers to gross wells multiplied by our working interest in such wells. 

 

30 

 

For the Years Ended 

December 31, 

 2011 2010 2009 

Production: 

Natural gas (MMcf) 7,318 7,593 9,266 

Oil (MBbl) 40 10 4 

NGLs (MBbl) 21 — —

Total production (MMcfe) 7,684 7,654 9,291 

Natural gas (MMcf/d) 20.0 20.8 25.4 

Oil (MBbl/d) 0.1 — —

NGLs (MBbl/d) 0.1 — —

Total daily production (MMcfe/d) 21.1 21.0 25.5 

Average sales price before hedging activity: 

Natural gas (per Mcf) $ 3.21 $ 3.51 $ 3.06 

Oil (per Bbl) $ 85.11 $ 72.63 $ 54.46 

NGLs (per Bbl) $ 52.47 $ — $ —

Average sales price after realized hedging activity: 

Natural gas (per Mcf) $ 4.56 $ 4.06 $ 4.36 

Selected operating expenses (in thousands): 

Production taxes $ 620 $ 370 $ 439 

Lease operating expenses 8,630 6,679 6,572 

Transportation, treating and gathering 4,501 4,654 1,547 

Depreciation, depletion and amortization 15,216 9,306 16,484 

General and administrative expense 11,365 14,638 15,649 

Selected operating expenses per Mcfe: 

Production taxes $ 0.08 $ 0.05 $ 0.05 

Lease operating expenses $ 1.12 $ 0.87 $ 0.71 

Transportation, treating and gathering $ 0.59 $ 0.61 $ 0.17 

Depreciation, depletion and amortization $ 1.98 $ 1.22 $ 1.77 

General and administrative expense $ 1.48 $ 1.91 $ 1.68 

Production costs (1) $ 1.62 $ 1.39 $ 0.76 

(1) Production costs include lease operating expense, insurance, gathering and workover expense and excludes ad valorem and severance taxes. 
Table of Contents 

Index to Financial Statements 

On December 31, 2011, we had a total of 10 gross (4.5 net) operated wells and six gross (1.2 net) non-operated wells in the process of being 

drilled or awaiting fracture stimulation in the Marcellus Shale, one gross (0.4 net) non-operated well being drilled in the Hilltop area of East Texas 

and eight gross (2.8 net) non-operated wells being drilled in Wyoming. 

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, 2011. The term "gross" represents the total number of acres in which we own a working interest. The term "net" 

represents our proportionate working interest resulting from our ownership in gross acres. 

 

 _______________ 

Undeveloped Acreage Expirations 

The table below summarizes by year our undeveloped acreage scheduled to expire. 

 

We have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally not 

exceeding three to five years. As is customary in the natural gas and oil industry, we can retain our interest in undeveloped acreage by commencing 

drilling activity that establishes commercial production sufficient to maintain the leases or by payment of delay rentals during the primary term of 

such leases. Of the 10,245 net acres expiring in 2012, we are currently focusing on the expiring acreage in East Texas and Marcellus West, where 

approximately 7,031 acres and 1,478 acres, respectively, are scheduled to expire in 2012. We have already extended or are in the process of 

extending approximately 2,500 

31 

 For the Years Ended December 31, 

 2011 2010 2009 

 Gross Net Gross Net Gross Net 

Exploratory wells: 

Productive 20.0 11.9 2.0 2.0 9.0 8.6 

Non-productive — — — — — —

Total 20.0 11.9 2.0 2.0 9.0 8.6 

Development wells: 

Productive 5.0 1.7 3.0 2.2 2.0 1.2 

Non-productive — — — — — —

Total 5.0 

 1.7  3.0  2.2  2.0  1.2 

 Undeveloped Acreage Developed Acreage 

 Gross Net Gross Net 

Marcellus Shale area, West Virginia and Pennsylvania (1) 

Marcellus West 39,281 18,047 4,138 1,901 

Marcellus East 59,461 53,021 3,498 3,155 

Total Marcellus Shale area 98,742 71,068 7,636 5,056 

Hilltop area, East Texas 30,843 15,283 10,305 6,585 

Powder River Basin, Wyoming and Montana 17,348 7,719 18,615 7,737 

Total 146,933  94,070  36,556  19,378 

(1) We believe that substantially all of our Marcellus Shale acreage is prospective. The Marcellus West acreage reflects that Atinum has earned 

their full joint venture interest. 

As of December 31, Gross Acres Net Acres 

% of Total Undeveloped 

Gross Acres Net Acres 

2012 20,472 10,245 14 % 11 % 

2013 39,444 22,421 27 % 24 % 

2014 15,559 12,567 11 % 13 % 

2015 17,078 11,959 12 % 13 % 

2016 and thereafter 21,577 17,361 15 % 18 % 

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Index to Financial Statements 

acres in East Texas. In Marcellus West, we anticipate drilling on the majority of the acreage before it expires. Our current plans in Marcellus East 

are to let approximately 1,623 acres scheduled for expiration in 2012 to expire. In the Powder River Basin area, 113 net acres are expiring in 2012. 

During 2010, we drilled 16 wells in shallower Devonian formations in the Appalachia area. These wells allow us to retain, for the life of production 

of our interest, certain undeveloped acreage above the Marcellus Shale for possible deeper drilling in the future. We do not expect to lose 

significant lease acreage in the Marcellus Shale as a result of our failure to drill or our reduction in drilling activities due to declines in natural gas 

prices. Based on our evaluation of current prospective economics, in 2012 we may try to renew expiring leases and, if not successful, the acreage 

will expire in East Texas. We may also allow additional acreage to expire in the future. 

Productive Wells 

The following table sets forth our working interest ownership in productive wells in the areas indicated as of December 31, 2011. The term 

"gross" represents the total number of wells in which we own a working interest. The term "net" represents our proportionate working interest 

resulting from our ownership in gross wells. Productive wells are wells that are currently capable of producing natural gas or oil. Wells that are 

completed in more than one producing horizon are counted as one well. 

 

Natural Gas and Oil Reserves 

Reserve Estimation 

The SEC rules expand the definition of natural gas and oil producing activities to include the extraction of saleable hydrocarbons from oil 

sands, shale, coal beds or other nonrenewable natural resources that are intended to be upgraded into synthetic natural gas or oil and activities 

undertaken with a view to such extraction. The use of new technologies is now permitted in the determination of proved reserves if those 

technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Proved reserves must be estimated using 

the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period, rather than the end-of-period price, when 

estimating whether reserve quantities are economical to produce. Likewise, the unweighted 12-month average price is used to compute 

depreciation, depletion and amortization. Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells 

scheduled to be drilled within five years of the date of booking. 

Third Party Review of Reserves Estimates 

For the years ended December 31, 2011 and 2010, reserves estimates for the Hilltop Area of East Texas and the Powder River Basin of 

Wyoming and Montana shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader 

of petroleum property analysis for industry and financial organizations and government agencies. Additionally, NSAI evaluated the reserves 

estimates for the Marcellus Shale for the year ended December 31, 2010. NSAI was founded in 1961 and performs consulting petroleum 

engineering services. A copy of NSAI’s summary reserve report is included as Exhibit 99.1 to this Form 10-K. For the year ended December 31, 

2011, reserves estimates for the Marcellus Shale shown herein have been independently evaluated by Wright & Company, Inc. ("Wright"), a 

national firm providing petroleum property analysis for industry and financial organizations with extensive experience in the Marcellus Shale. 

Wright was founded in 1988 and performs consulting petroleum engineering services. A copy of Wright's summary reserve report is included as 

Exhibit 99.2 to this Form 10-K. 

Within NSAI, the technical persons primarily responsible for preparing the reserves estimates set forth in the NSAI reserve report 

incorporated herein are Mr. Dan Paul Smith and Mr. William (Bill) J. Knights. Mr. Smith has been practicing consulting petroleum engineering at 

NSAI since 1980. He is a Registered Professional Engineer in the State of Texas and has over 30 years of practical experience in petroleum 

engineering and in the estimation and evaluation of reserves. He graduated from Mississippi State University in 1973 with a Bachelor of Science 

Degree in Petroleum Engineering. Mr. Knights has been practicing consulting petroleum geology at NSAI since 1991. He is a Certified Petroleum 

Geologist and Geophysicist in the State of Texas and has over 30 years of practical experience in petroleum geosciences, with over 20 years 

experience in the 

32 

 Productive Wells 

 Natural Gas Oil Total Wells 

 Gross Net Gross Net Gross Net 

Appalachia, West Virginia and Pennsylvania 51.0 31.3 — — 51.0 31.3 

Hilltop area, East Texas 27.0 18.7 5.0 5.0 32.0 23.7 

Powder River Basin, Wyoming and Montana 471.0 207.8 — — 471.0 207.8 

Total 549.0 

 257.8  5.0  5.0  554.0  262.8 
Table of Contents 

Index to Financial Statements 

estimation and evaluation of reserves. He graduated from Texas Christian University in 1981 with a Bachelor of Science Degree in Geology and in 

1984 with a Master of Science Degree in Geology. Both technical principals meet or exceed the requirements regarding qualifications, 

independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves 

Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to 

engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. 

Within Wright, the technical person primarily responsible for preparing the reserves estimates set forth in the Wright reserve report 

incorporated herein is Mr. D. Randall Wright. Mr. Wright has been practicing consulting petroleum engineering at Wright since 1988, the year in 

which he founded the company. He is a Registered Professional Engineer in the State of Texas and has over 38 years of practical experience in 

petroleum engineering and in the estimation and evaluation of reserves. He has a Master of Science degree in Mechanical Engineering from 

Tennessee Technological University. The technical principal meets or exceeds the requirements regarding qualifications, independence, objectivity 

and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the 

Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as 

well as applying SEC and other industry reserves definitions and guidelines. 

Qualifications of Technical Persons and Internal Controls Over Reserves Estimates 

The preparation of our reserve estimates are completed in accordance with our prescribed internal control procedures and are subject to 

management review. We maintain an internal technical team consisting of our Senior Reservoir Engineer and several geoscience professionals, who 

work closely with NSAI and Wright to ensure the integrity, accuracy and timeliness of data furnished to NSAI and Wright in their reserve review 

and estimation process. Throughout the year, our internal technical team meets regularly with representatives of NSAI and Wright to review 

properties and discuss methods and assumptions used in NSAI and Wright’s preparation of the year-end reserves estimates. We provide historical 

information to NSAI and Wright for our largest producing properties, including with respect to ownership interest, oil and gas production, well test 

data, commodity prices and operating and development costs. NSAI and Wright perform independent analysis, and differences are reviewed with 

our senior management. In some cases, additional meetings are held to review additional reserve work performed by our technical team related to 

any identified reserve differences. Historical variances between our internal reserves estimates and NSAI and Wright's estimates have been less than 

5%. In addition, our Board of Directors has a reserves review committee, which is chaired by an independent director. The reserves review 

committee meets at least once a year and is specifically designated to review the year-end reserves reporting and the reserves estimation process, 

while our senior management reviews and approves any internally estimated significant changes to our proved reserves on a quarterly basis. The 

year-end NSAI and Wright reserve reports are reviewed by the reserves review committee, together with representatives of NSAI, Wright and our 

internal team. 

Since 2006, all of our reserve estimates have been reviewed and approved by our Senior Reservoir Engineer, who reports directly to our Chief 

Financial Officer. Our Senior Reservoir Engineer attended Texas A&M University and graduated in 1978 with a Bachelor of Science degree in 

Reservoir Engineering and has been involved in evaluations and the estimation of reserves and resources for over 29 years. During the year, our 

technical team may also perform separate, detailed technical reviews of reserve estimates for significant acquisitions or for properties with 

problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operational conditions. 

Technologies Used in Reserves Estimation 

Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with 

reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, 

operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or 

natural gas actually recovered will equal or exceed the estimate. The SEC allows the use of techniques that have been proven effective by actual 

production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable 

certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have 

been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous 

formation. To achieve reasonable certainty, our technical team employs technologies that have been demonstrated to yield results with consistency 

and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, empirical 

evidence through drilling results and well performance, well logs, geologic maps and available downhole and production data, seismic data, well 

test data and reservoir simulation modeling. 

33 
Table of Contents 

Index to Financial Statements 

Estimated Proved Reserves 

Our proved reserves information as of December 31, 2011 included in this Form 10-K was estimated by NSAI and Wright using standard 

engineering and geosciences procedures and methods used in the petroleum industry. The technical personnel responsible for preparing the reserve 

estimates at NSAI and Wright meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the 

Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. 

In accordance with SEC regulations, estimates of our proved reserves and future net revenues as of December 31, 2011 were made using 

benchmark prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month price for natural gas and oil (“SEC pricing”). 

Key natural gas prices utilized were the Henry Hub price of $ 4.12 per MMBtu, the Katy Hub price of $ 4.07 per MMBtu and the CIG price of $ 

3.93 per MMBtu. NSAI utilized a West Texas Intermediate ("WTI") posted oil price of $ 92.71 per barrel, and Wright utilized a WTI spot oil price 

of $96.19 per barrel. 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 in accordance with sales contracts and for energy content, quality, transportation, compression and gathering fees and regional 

price differentials. Estimated quantities of proved reserves and future net revenues are affected by natural gas and oil prices, which have fluctuated 

significantly in recent years. All of our proved reserves are located onshore within the United States. 

The following table summarizes our estimated proved reserves as of December 31, 2011: 

 

________________ 

Pricing Assumptions 

In accordance with the SEC pricing guidelines, our December 31, 2011 report of estimated proved reserves and future net revenues were 

made using the 12-month unweighted arithmetic average of the first-day-of-the-month prices. These prices are held constant in accordance with 

SEC guidelines for the life of the wells included in the reserve report but are adjusted by lease in accordance with sales contracts and for energy 

content, quality, transportation, compression and gathering fees and regional price differentials. 

34 

 Total Proved Reserves 

 Producing Non-producing Undeveloped Total 

Natural gas (MMcf) 49,397 15,664 26,591 91,652 

NGLs (MBbls) 1,075 264 1,418 2,757 

Oil (MBbls) 729 175 1,017 1,921 

Total proved reserves (MMcfe) 60,219 18,300 41,197 119,716 

PV-10 (in thousands) (1) $118,270 $31,576 $67,271 $217,117 

(1) PV-10 represents the present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proved 

reserves. PV-10 is a non-U.S. GAAP financial measure because it excludes the effects of income taxes. We believe that PV-10 is a useful 

measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may use the measure as a 

basis for comparison of the relative size and value of our reserves to other companies. PV-10 should not be considered as an alternative to 

standardized measure of discounted future net cash flows as defined under U.S. GAAP. We presently have approximately $134.3 million of net 

operating loss carryforwards, $50.6 million of foreign tax credit carryforwards and $193.6 million of remaining property tax basis for Federal 

income tax purposes. Based on these carryforwards and current and future property tax basis, future income taxes discounted at 10% total $4.3 

million, resulting in a standardized measure of discounted future net cash flows as of December 31, 2011 of $212.8 million. 
Table of Contents 

Index to Financial Statements 

The following table summarizes our proved reserves by geographic area as of December 31, 2011: 

SEC Pricing Case Proved Reserves (1) 

 

________________ 

Proved Undeveloped Reserves (“PUDs”) 

As of December 31, 2011, our PUDs totaled 41.2 Bcfe, representing a 390% increase from our PUDs as of December 31, 2010. All of our 

PUDs at year-end 2011 were associated with the Marcellus Shale. The December 31, 2011 PUDs consisted of 19 gross (7.5 net) Marcellus 

horizontal wells in Appalachia. The increase in PUD well locations in 2011 is due to the successful Marcellus Shale drilling program in 2011. 

During 2011, we did not convert any PUD reserves to proved developed reserves. The following table summarizes our PUD activity during the year 

ended December 31, 2011: 

________________ 

Estimated future development costs relating to the development of 2011 year-end PUDs is $43.9 million of which 2012 and 2013 

expenditures are $40.8 million and $2.5 million, respectively. Under current SEC requirements, PUD reserves may only be booked if they related 

to wells scheduled to be drilled within five years of the original date of booking unless specific circumstances justify a longer time. All of our 

PUDs at December 31, 2011 are scheduled to be drilled by 2013, which is within five years from the date initially recorded as PUD reserves. We 

may be required to remove our PUDs if we do not drill those reserves within the required five year time frame. 

35 

 

Natural 

Gas 

(MMcf) 

NGLs 

(MBbls) 

Oil 

(MBbls) MMcfe 

% Proved 

Developed 

PV-10 (2) 

(in thousands) 

Hilltop area, East Texas 34,212 — 7 34,252 100 % $ 42,486 

Appalachia, West Virginia and Pennsylvania 56,010 2,757 1,914 84,034 51 % 174,340 

Powder River Basin, Wyoming and Montana 1,395 — — 1,395 100 % 216 

Other 35 — — 35 100 % 75 

Total 91,652  2,757 1,921  119,716  66 % $ 217,117 

(1) Key natural gas prices utilized were the Henry Hub price of $4.12 per MMBtu, the Katy Hub price of $4.07 per MMBtu and the CIG price of 

$3.93 per MMBtu. NSAI utilized a WTI posting oil price of $92.71 per barrel and Wright utilized a WTI spot oil price of $96.19 per barrel. 

(2) PV-10 represents the present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proved 

reserves. PV-10 is a non-U.S. GAAP financial measure because it excludes the effects of income taxes. We believe that PV-10 is a useful 

measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may use the measure as a 

basis for comparison of the relative size and value of our reserves to other companies. PV-10 should not be considered as an alternative to 

standardized measure of discounted future net cash flows as defined under U.S. GAAP. We presently have approximately $134.3 million of net 

operating loss carryforwards, $50.6 million of foreign tax credit carryforwards and $193.6 million of remaining property tax basis for Federal 

income tax purposes. Based on these carryforwards and current and future property tax basis, future income taxes discounted at 10% total $4.3 

million, resulting in a standardized measure of discounted future net cash flows as of December 31, 2011 of $212.8 million. 

 

Natural 

Gas 

(MMcf) 

NGLs 

(MBbls) 

Oil 

(MBbls) MMcfe 

PUDs as of December 31, 2010 8,320 — 17 8,420 

Extensions and discoveries, less related costs 26,157 1,418 1,000 40,663 

Revisions of previous estimates (1) (7,885 ) — — (7,885 ) 

PUDs as of December 31, 2011 26,592  1,418  1,017  41,198 

(1) The downward revision of previous estimates of natural gas is attributable to the decision to forgo the recording of an East Texas PUD location 

due to low natural gas prices which would have resulted in drilling beyond the five year maximum period from the date initially recorded as a 

PUD. 
Table of Contents 

Index to Financial Statements 

Item 3. Legal Proceedings 

Information about our legal proceedings is set forth in Note 15, “Commitments and Contingencies – Litigation” to our consolidated financial 

statements, which begin on page F-1 of this Form 10-K. 

Item 4. Mine Safety Disclosures. 

Not applicable. 

PART II 

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

Market Information 

Our common stock is traded on the NYSE Amex LLC under the symbol “GST,” and until July 6, 2009 on the Toronto Stock Exchange under 

the symbol “YGA.” On July 6, 2009, we voluntarily delisted our common shares on the Toronto Stock Exchange. The following table sets forth the 

high and low sales prices of our common stock for the 2011 and 2010 annual periods. 

 

The last reported sale price of our common shares on the NYSE Amex on March 6, 2012 was $2.77. 

Shareholders 

As of March 6, 2012, there were 408 shareholders of record who owned our common shares. 

Dividends 

We have never declared or paid any cash dividends on our common stock. 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 stock in the foreseeable future. In addition, 

the Revolving Credit Facility prohibits us from paying cash dividends on our common shares 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 

We did not have any sales of unregistered securities during the year ended December 31, 2011. 

Item 6. Selected Financial Data 

36 

 NYSE Amex 

 High Low 

2011: 

Fourth quarter $ 3.96 $ 2.63 

Third quarter $ 4.86 $ 3.00 

Second quarter $ 4.85 $ 3.20 

First quarter $ 4.95 $ 4.02 

2010: 

Fourth quarter $ 5.44 $ 3.46 

Third quarter $ 4.27 $ 2.85 

Second quarter $ 5.77 $ 3.40 

First quarter $ 5.70 $ 4.25 
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 selected historical financial data should be read in connection with 

Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited Consolidated Financial 

Statements and related notes included elsewhere in this Form 10-K. 

Financial information as of and for the year ended December 31, 2010 includes litigation settlement expense of $21.7 million. Financial 

information as of and for the years ended December 31, 2009, 2008, 2007 and 2006 include impairment of natural gas and oil properties of $68.7 

million, $14.2 million, $28.5 million and $56.3 million, respectively. Financial information as of and for the years ended December 31, 2009 and 

2007 reflect gains on sale of assets of $211.2 million and $38.5 million, respectively. Additionally, financial information as of and for the years 

ended December 31, 2009 and 2007 include expenses related to the early extinguishment of debt of $15.9 million and $15.7 million, respectively. 

 

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

Overview 

We are an independent energy company engaged in the exploration, development and production of natural gas and oil in the U.S. Our 

principal business activities include the identification, acquisition, and subsequent exploration and development of natural gas and oil properties 

with an emphasis on unconventional reserves, such as shale resource plays. We are currently pursuing the development of liquids-rich natural gas in 

the Marcellus Shale in the Appalachia area of West Virginia and central and southwestern Pennsylvania. We also hold prospective acreage in the 

deep Bossier play in the Hilltop area of East Texas and conduct limited CBM development activities within the Powder River Basin of Wyoming 

and Montana. 

Parent is a Canadian corporation, incorporated in Alberta in 1987 and subsisting under the Business Corporations Act (Alberta), with its 

common shares listed on the NYSE Amex under the symbol “GST.” Parent is a holding company. Substantially all of the Company's operations are 

conducted through, and substantially all of its assets are held by, Parent's primary operating subsidiary, Gastar USA, and its subsidiaries. Gastar 

USA's Series A Preferred Stock is listed on the NYSE Amex under the symbol "GST.PRA." 

Our current operational activities are conducted primarily in the United States. As of December 31, 2011, our major assets consist of 

approximately 106,400 gross ( 76,100 net) acres in the Marcellus Shale in West Virginia and southwestern Pennsylvania, approximately 41,100 

gross ( 21,900 net) acres in the Bossier play in the Hilltop area of East Texas, and approximately 35,900 gross ( 15,400 net) acres in the Powder 

River Basin of Wyoming and Montana. During the past three years, we spent approximately $225.1 million in acreage, seismic, capitalized interest, 

drilling advances, reserve acquisition and 

37 

 As of and for the Years Ended December 31, 

 2011 2010 2009 2008 2007 

 (in thousands, except per share data) 

Consolidated Statements of Operations: 

Revenues $ 40,235 $ 42,768 $ 32,869 $ 63,219 $ 34,565 

Loss from operations $ (631 ) $ (15,019 ) $ (76,930 ) $ (976 ) $ (42,514 ) 

Net income (loss) $ (1,764 ) $ (12,460 ) $ 48,846 $ (5,361 ) $ (30,540 ) 

Income (loss) per share: 

Basic $ (0.03 ) $ (0.25 ) $ 1.06 $ (0.13 ) $ (0.75 ) 

Diluted $ (0.03 ) $ (0.25 ) $ 1.06 $ (0.13 ) $ (0.75 ) 

Weighted average common shares outstanding 

Basic 63,004 49,814 46,103 41,420 40,566 

Diluted 63,004 49,814 46,210 41,420 40,566 

Consolidated Balance Sheets: 

Property, plant and equipment, net $ 285,740 $ 215,115 $ 162,661 $ 252,527 $ 157,120 

Total assets $ 334,503 $ 247,352 $ 296,238 $ 288,437 $ 261,750 

Long-term liabilities $ 39,438 $ 14,295 $ 18,371 $ 5,095 $ 137,076 

Total shareholders’ equity $ 207,803 $ 207,391 $ 164,896 $ 101,582 $ 95,269 
Table of Contents 

Index to Financial Statements 

exploratory and development drilling on this acreage. We have not attained positive net income from operations in the past three years. There can 

be no assurance that operating income and net earnings will be achieved in future periods. As we continue the exploitation and development drilling 

in the Marcellus Shale, we expect to show further improvement in our operations. 

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 then current future period 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 execute to mitigate the volatility in natural gas and oil prices in future periods. 

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. 

2011 Highlights 

Marcellus Shale Drilling Program. Du ring 2011, we focused our efforts and spent the majority of our capital on our liquids-rich acreage in 

the Marcellus Shale. As of December 31, 2011, we had drilled and cased 17 gross (7.2 net) operated wells and were in various stages of drilling on 

five gross (2.5 net) operated wells in Marshall County, West Virginia, under the Atinum Joint Venture. Of the wells drilled and cased, nine gross 

(four net) wells were on production at December 31, 2011. Additionally, at December 31, 2011, we had commenced drilling operations on a five 

horizontal well pad and a three horizontal well pad. At December 31, 2011, our proved reserves attributable to our Marcellus Shale acreage were 

approximately 84.0 Bcfe, a significant increase from-year end 2010 reserves of 2.8 Bcfe. Marcellus Shale proved reserves represented 

approximately 70% of our total proved reserves at December 31, 2011. Oil and NGLs reserves comprised approximately 33% of the total Marcellus 

Shale proved reserves at year end 2011. 

Public Offering of Gastar USA Series A Preferred Stock. On June 23, 2011, Gastar USA sold an aggregate of 646,295 shares of Series A 

Preferred Stock through a best efforts underwritten public offering. In connection with the offering, Parent entered into a guarantee agreement, 

whereby it will fully and unconditionally guarantee the payment of dividends that have been declared by the board of directors of Gastar USA, 

amounts payable upon redemption or liquidation, dissolution or winding up, and any other amounts due with respect to the Series A Preferred 

Stock, to the extent described in the guarantee agreement. The net proceeds to Gastar USA from the offering were approximately $13.6 million 

after deducting underwriting discounts, commissions and estimated offering expenses. The net proceeds were primarily used to repay borrowings 

under the Revolving Credit Facility. 

On June 29, 2011, Gastar USA entered into an at-the-market sales agreement ("ATM Agreement") with McNicoll, Lewis & Vlak LLC 

("MLV"). According to the provisions of the ATM Agreement, Gastar USA may offer and sell from time to time up to 3,400,000 shares of Series A 

Preferred Stock through MLV, as its sales agent. Sales of the units will be made by means of ordinary brokers’ transactions on the NYSE at market 

prices, in block transactions or as otherwise agreed between Gastar USA and MLV. During the period ended December 31, 2011, Gastar USA sold 

718,248 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $13.9 million. We plan to continue issuing Series A 

Preferred Stock under the ATM Agreement in the future depending on our capital expenditures program and market conditions. 

38 

• The level and success of exploration and development activity; 

• The sales prices of natural gas and 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 

Financial Highlights 

Our consolidated financial statements reflect total revenue of $ 40.2 million on total volumes of 7.7 Bcfe for the year ended December 31, 

2011. Our operating loss for the year ended December 31, 2011 was $ 631,000 and included depreciation, depletion and amortization expense of $ 

15.2 million. 

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. 

For additional information about production volumes, prices of natural gas and oil and selected operating expenses, see Item 2. Properties – 

Production, Prices and Operating Expenses of this Form 10-K. 

The following table provides a summary of our revenues, production and operating expenses for the periods indicated: 

 

39 
Table of Contents 

Index to Financial Statements 

Year Ended December 31, 2011 compared to Year Ended December 31, 2010 

Revenues. Natural gas, oil and NGLs revenues were $37.9 million for the year ended December 31, 2011, up 20% from $31.6 million for the 

year ended December 31, 2010. Average daily production on an equivalent basis was 21.1 MMcfe/d for the year ended December 31, 2011 

compared to 21.0 MMcfe/d for the same period in 2010. This increase in revenues was the result of a 20% increase in weighted average prices, 

primarily resulting from increased oil prices and higher oil and NGL volumes for the year ended December 31, 2011. During 2011, our East Texas 

production averaged 17.3 MMcfe/d compared to 2010 production of 18.6 MMcfe/d, a 7% decrease. Production in Appalachia averaged 2.4 

MMcfe/d compared to 2010 production of 0.4 MMcfe/d, a 500% increase. Wyoming and other areas production declined by approximately 28%, 

primarily due to lower Wyoming production resulting from reductions in compression to reduce cash costs and limited capital activity. 

Liquids revenues (oil and NGLs including condensate) represented approximately 16% of our total revenues before hedge 

40 

 Year Ended December 31, 

 2011 2010 2009 

 

(In thousands, except per unit 

amounts) 

Revenues: 

Natural gas $ 33,391 $ 30,812 $ 40,407 

Oil 3,416 742 229 

NGLs 1,092 — —

Unrealized natural gas hedge gain (loss) 2,336 11,214 (7,767 ) 

Total revenues $ 40,235 $ 42,768 $ 32,869 

Production: 

Natural gas (MMcf) 7,318 7,593 9,266 

Oil (MBbl) 40 10 4 

NGLs (MBbl) 21 — —

Total production (MMcfe) 7,684 7,654 9,291 

 

Natural gas (MMcf/d) 20.0 20.8 25.4 

Oil (MBbl/d) 0.1 — —

NGL (MBbl/d) 0.1 — —

Total daily production (MMcfe/d) 21.1 21.0 25.5 

Average sales price per unit: 

Natural gas per Mcf, excluding impact of realized hedging activities $ 3.21 $ 3.51 $ 3.06 

Natural gas per Mcf, including impact of realized hedging activities $ 4.56 $ 4.06 $ 4.36 

Oil per Bbl $ 85.11 $ 72.63 $ 54.46 

NGLs per Bbl $ 52.47 $ — $ —

Selected operating expenses (in thousands): 

Production taxes $ 620 $ 370 $ 439 

Lease operating expense 8,630 6,679 6,572 

Transportation, treating and gathering 4,501 4,654 1,547 

Depreciation, depletion and amortization 15,216 9,306 16,484 

Impairment of oil and gas properties — — 68,729 

General and administrative expense 11,365 14,638 15,649 

Selected operating expenses per Mcfe: 

Production taxes $ 0.08 $ 0.05 $ 0.05 

Lease operating expenses $ 1.12 $ 0.87 $ 0.71 

Transportation, treating and gathering $ 0.59 $ 0.61 $ 0.17 

General and administrative expenses $ 1.48 $ 1.91 $ 1.68 

Depreciation, depletion and amortization $ 1.98 $ 1.22 $ 1.77 
Table of Contents 

Index to Financial Statements 

gains for the year ended December 31, 2011. Due to lower natural gas prices, we are focusing the majority of our 2012 drilling activity in the 

liquids-rich portions of the Marcellus Shale. If current trends of natural gas prices relative to oil prices continue and assuming that we successfully 

and timely complete our 2012 drilling activity, we expect our liquids revenues to increase substantially as a percentage of total revenues before 

hedging gains or losses in 2012. 

During the year ended December 31, 2011, approximately 91% of our total natural gas production was hedged. The realized effect of hedging 

on natural gas sales was an increase of $9.9 million in natural gas revenues resulting in an increase in total natural gas price realized from $ 3.21 per 

Mcf to $ 4.56 per Mcf for the year ended December 31, 2011. The realized hedge impact includes a benefit of $1.7 million for amortization of 

prepaid call sale and put purchase premiums. Excluding the non-cash amortization, the realized effect of hedging was an increase in revenues of 

$8.2 million, which was comprised of $12.1 million of NYMEX hedge gains offset by $632,000 of regional basis losses and payment of deferred 

put premiums of $3.3 million. During the year ended December 31, 2010, the realized effect of hedging on natural gas sales was an increase of $4.1 

million in natural gas and oil revenues resulting in an increase in total price realized from $3.51 per Mcf to $4.06 per Mcf. The 2010 realized hedge 

impact included a loss of $1.4 million of non-cash amortization of prepaid call sale and put purchase premiums and payment of deferred put 

premiums of $1.1 million. 

Unrealized natural gas hedge gain was $ 2.3 million for the twelve months ended December 31, 2011 compared to $11.2 million for the 

twelve months ended December 31, 2010. The decrease in unrealized natural gas hedge impact was the result of a decrease in hedge prices as 

compared to changes in future NYMEX gas prices. 

Production taxes. We reported production taxes of approximately $ 620,000 for the year ended December 31, 2011, up from $370,000 for the 

year ended December 31, 2010. The increase was primarily the result of higher revenues in West Virginia due to increased natural gas, oil and 

NGLs production, partially offset by lower revenues in Wyoming due to lower production volumes. 

Lease operating expenses. We reported lease operating expenses of $ 8.6 million for the year ended December 31, 2011, up from $6.7 million 

for the year ended December 31, 2010. This increase was primarily due to higher non-recurring workover expense. Our lease operating expenses 

were $ 1.12 per Mcfe for the year ended December 31, 2011, up 29% from $0.87 per Mcfe for the same period in 2010. Excluding workover 

expense and other non-recurring costs, our lease operating expenses were $6.5 million or $0.85 per Mcfe for the year ended December 31, 2010, 

compared to $5.9 million or $0.77 per Mcfe for the same period in 2010. 

 

The 43% increase from December 31, 2010 to December 31, 2011 in lease operating expense per Mcfe for the Hilltop area, East Texas was 

primarily the result of higher non-recurring workover costs and lower volumes. Workover costs in the Hilltop area, East Texas for 2011 and 2010 

were $2.1 million and $760,000, or $0.33 per Mcfe and $0.11 per Mcfe, respectively. The 67% decrease from December 31, 2010 to December 31, 

2011 in lease operating expense per Mcfe for the Appalachia area was primarily the result of increased production. The 41% increase from 

December 31, 2010 to December 31, 2011 in lease operating expense per Mcfe in Other was primarily related to Powder River Basin CBM 

production declines. 

Transportation, treating and gathering. We reported transportation expenses of $ 4.5 million for the year ended December 31, 2011, down 

from $4.7 million for the year ended December 31, 2010. This decrease was primarily due to lower costs in Wyoming due to lower CBM 

production. The twelve months ended December 31, 2011 includes $1.5 million of charges under our Hilltop gas gathering agreement with Hilltop 

Resort GS, LLC ("Hilltop Resort") compared to $1.3 million of such charges for the year ended December 31, 2010. Such charges resulted from 

actual production volumes being less than minimum contractual volume requirements. 

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) was $ 15.2 million for the year ended 

December 31, 2011, up from $9.3 million for the year ended December 31, 2010. The increase in DD&A expense was the result of a 62% increase 

in DD&A rate per Mcfe and a slight increase in production volumes primarily attributable to increased Appalachia production. The DD&A rate for 

the year ended December 31, 2011 was $ 1.98 per Mcfe, as compared to 

41 

 

Lease Operating Expense 

For the Year Ended 

December 31, 2011 

Lease Operating Expense 

For the Year Ended 

December 31, 2010 

% Change 

 (in thousands) ($ per Mcfe) (in thousands) ($ per Mcfe) of $ per Mcfe 

Hilltop area, East Texas $ 5,863 $ 0.93 $ 4,399 $ 0.65 43% 

Appalachia 832 $ 0.97 393 $ 2.96 (67 )% 

Other 1,935 $ 3.72 1,887 $ 2.63 41% 

Total $ 8,630 

 $ 1.12 $ 6,679  $ 0.87 29% 
Table of Contents 

Index to Financial Statements 

$1.22 for the same period in 2010. The increase in the DD&A rate is primarily due to higher proved costs associated with recent East Texas wells 

drilled and additional allocation of $63.8 million of undeveloped East Texas leasehold costs from unproved to proved properties based on recent 

drilling results and reduced 2012 drilling activity due to a decline in natural gas prices. 

General and administrative expenses. We reported general and administrative expenses of $ 11.4 million for the year ended December 31, 

2011, down from $14.6 million for the year ended December 31, 2010. Non-cash stock-based compensation expense, which is included in general 

and administrative expenses, was $2.6 million and $2.8 million for the years ended December 31, 2011 and 2010, respectively. This decrease in 

stock-based compensation expense was due primarily to the forfeiture of previously issued unvested awards as a result of director and employee 

resignations, prior year awards being fully amortized and recently issued awards having a lower fair value than awards issued in prior years. 

Excluding stock-based compensation expense, general and administrative expense decreased $3.0 million to $8.8 million for the year ended 

December 31, 2011 compared to $11.8 million for the year ended December 31, 2010. This decrease was primarily due to lower legal fees as a 

result of the Classic Star litigation settlement in November 2010. 

Litigation settlement expense. We reported litigation settlement expense of $21.7 million for the twelve months ended December 31, 2010 

primarily resulting from our settlement with the plaintiffs of the seven ClassicStar Mare Lease Litigation suits in December 2010 (for additional 

information regarding the settlement of this matter, see Note 15, "Commitments and Contingencies Litigation," to our consolidated financial 

statements included in this Form 10-K. 

Interest expense. We reported interest expense of $ 113,000 for the year ended December 31, 2011 compared to $150,000 for the year ended 

December 31, 2010. Interest expense excludes $817,000 and $633,000 of capitalized interest in 2011 and 2010, respectively, which related to 

capital expenditures for undeveloped projects in East Texas, West Virginia and Pennsylvania. Excluding capitalized interest, interest expense 

increased $147,000 from December 31, 2010 to December 31, 2011 due to higher outstanding debt balances throughout the year ended December 

31, 2011 compared to the year ended December 31, 2010. 

Investment income and other. We reported investment income of $ 10,000 for the year ended December 31, 2011 compared to $1.3 million 

for the year ended December 31, 2010. The decrease in investment income is primarily due to interest earned during 2010 on the Australian term 

deposit established in conjunction with the sale of our Australian properties in July 2009 for the future tax payment related to the sale. At maturity 

on June 1, 2010, the term deposit was used to settle the Australian tax liability resulting from the Australian property sale in 2009 and, thus, 

resulting in no comparable investment income during 2011. 

Warrant derivative loss. For the year ended December 31, 2010 we reported a $205,000 unrealized gain related to the fair value measurement 

of our warrants outstanding. At December 31, 2011, the warrants had expired and were no longer outstanding. 

Foreign transaction gain (loss). We reported a foreign transaction loss of $ 6,000 for the year ended December 31, 2011 compared to a gain 

of $353,000 for the year ended December 31, 2010. The decrease in foreign transaction gain was primarily due to the decrease in Australian 

denominated cash and accounts receivable balances arising from the sale of the Australian properties in 2009. 

Provision for income tax expense (benefit). We reported neither an income tax benefit nor provision for the year ended December 31, 2011. 

We reported $804,000 of income tax benefit for the year ended December 31, 2010. The income tax benefit for the twelve months ended 

December 31, 2010 was primarily due to a $1.0 million downward adjustment of the tax expense related to the sale of the Australian properties after 

final review from the Australian Tax Office partially offset by withholding tax on the interest income earned from the Australian term deposit and a 

benefit for previously accrued state income taxes. 

Dividends on Preferred Stock. We reported dividends on our Series A Preferred Stock of $1.0 million for the year ended December 31, 2011. 

The Series A Preferred Stock had a stated value of approximately $27.5 million at December 31, 2011 and carries a cumulative dividend rate of 

8.625% per annum. There were no shares of Series A Preferred Stock outstanding during the year ended December 31, 2010. 

Year Ended December 31, 2010 compared to Year Ended December 31, 2009 

Revenues. Natural gas and oil revenues were $31.6 million for the year ended December 31, 2010, down 22% from $40.6 million for the year 

ended December 31, 2009. Average daily production on an equivalent basis was 21.0 MMcfe/d for the year ended December 31, 2010 compared to 

25.5 MMcfe/d for the same period in 2009. This decrease in revenues was the result of an 18% decrease in production and a 6% decrease in prices. 

The decrease in production is primarily due to delays in new wells 

42 
Table of Contents 

Index to Financial Statements 

coming on production to offset the production decline on existing wells and lower Belin #1 production due to the well not producing for the 

majority of the second quarter of 2010 compared to the first half of 2009 benefitting from the initial high rates of production from the well. During 

2010, our East Texas production averaged 18.6 MMcfe/d compared to 2009 production of 21.8 MMcfe/d, a 15% decrease. Production in Wyoming 

and other areas declined by approximately 35%, primarily due to lower Wyoming production resulting from reductions in compression to reduce 

cash costs and only one Wyoming well being drilled in 2010. 

During the year ended December 31, 2010, approximately 94% of our total natural gas production was hedged, of which only 45% had price 

ceiling limitations. The realized effect of hedging on natural gas sales for the year ended December 31, 2010 was an increase of $4.1 million in 

revenues resulting in an increase in total natural gas price received from $3.51 per Mcf to $4.06 per Mcf. The realized hedge impact includes a 

reduction of $1.4 million for non-cash amortization of prepaid put purchase and call sale premiums. Excluding the non-cash amortization, the 

realized effect of hedging was an increase in revenues of $5.6 million comprised of $8.4 million of NYMEX hedge gains offset by $1.7 million of 

regional basis losses and deferred put premium payments of $1.1 million. 

Unrealized natural gas hedge gain was $11.2 million for the twelve months ended December 31, 2010 compared to an unrealized natural gas 

hedge loss of $7.8 million for the twelve months ended December 31, 2009. The increase in unrealized natural gas hedge impact was the result of 

the benefit from lower future NYMEX gas prices offset by lower hedged volumes and losses related to basis differentials. 

Production taxes. We reported production taxes of approximately $370,000 for the year ended December 31, 2010, down from $439,000 for 

the year ended December 31, 2009. The decrease was primarily the result of lower revenues in Wyoming due to lower production volumes. 

Lease operating expenses. We reported lease operating expenses of $6.7 million for the year ended December 31, 2010, up slightly from $6.6 

million for the year ended December 31, 2009. This increase was primarily due to higher non-recurring workover expense. Our lease operating 

expenses were $0.87 per Mcfe for the year ended December 31, 2010, up 23% from $0.71 per Mcfe for the same period in 2009. Excluding 

workover expense and other non-recurring costs, our lease operating expenses were $5.9 million or $0.77 per Mcfe for the year ended 

December 31, 2010, compared to $6.0 million or $0.62 per Mcfe for the same period in 2009. 

 

The 29% increase from December 31, 2009 to December 31, 2010 in lease operating expense per Mcfe for the Hilltop area, East Texas was 

primarily the result of lower volumes and higher non-recurring workover costs. Workover costs in the Hilltop area, East Texas for 2010 and 2009 

were $760,000 and $344,000, or $0.11 per Mcfe and $0.04 per Mcfe, respectively. The 39% increase from December 31, 2009 to December 31, 

2010 in lease operating expense per Mcfe in Other was primarily related to Powder River Basin CBM production declines. 

Transportation, treating and gathering. We reported transportation expenses of $4.7 million for the year ended December 31, 2010, up from 

$1.5 million for the year ended December 31, 2009. This increase was primarily due to gathering charges in East Texas under the Hilltop Gathering 

Agreement, effective November 2009 in conjunction with the sale of our Hilltop Gathering System, partially offset by lower transportation costs in 

Wyoming as a result of lower production. The twelve months ended December 31, 2010 included $1.3 million of charges under the Hilltop 

Gathering Agreement due to actual production volumes being less than minimum contractual volume requirements. 

Depreciation, depletion and amortization. DD&A was $9.3 million for the year ended December 31, 2010, down from $16.5 million for the 

year ended December 31, 2009. The decrease in DD&A expense was the result of a 31% decrease in DD&A rate per Mcfe and an 18% decrease in 

production volumes primarily attributable to delays in drilling and operational issues on the Belin #1. The DD&A rate for the year ended 

December 31, 2010 was $1.22 per Mcfe, as compared to $1.77 for the same period in 2009. The decrease in the DD&A rate is primarily due to 

lower proved costs due to ceiling impairments recorded during 2009 and gathering sales proceeds credited to proved property costs in late 2009. 

43 

 

Lease Operating Expense 

For the Year Ended 

December 31, 2010 

Lease Operating Expense 

For the Year Ended 

December 31, 2009 % Change 

 (in thousands) ($ per Mcfe) (in thousands) ($ per Mcfe) of $ per Mcfe 

Hilltop area, East Texas $ 4,399 $ 0.65 $ 4,023 $ 0.50 29 % 

Other $ 2,280 $ 2.68 2,549 $ 1.93 39 % 

Total $ 6,679 

 $ 0.87 $ 6,572  $ 0.71 23 % 
Table of Contents 

Index to Financial Statements 

Impairment of natural gas and oil properties. We did not record an impairment of natural gas and oil properties for the year ended 

December 31, 2010. We recorded an impairment of natural gas and oil properties of $68.7 million for the year ended December 31, 2009. The 2009 

impairment was the result of a significant decline in natural gas prices at March 31, 2009. Henry Hub natural gas prices at March 31, 2009 declined 

37% from December 31, 2008 prices resulting in estimated future net revenues being based on a weighted average price of $2.64, held constant, 

discounted at 10% plus unproven properties at historical costs. 

General and administrative expenses. We reported general and administrative expenses of $14.6 million for the year ended December 31, 

2010, down from $15.6 million for the year ended December 31, 2009. Non-cash stock-based compensation expense, which is included in general 

and administrative expenses, was $2.8 million and $3.5 million for the years ended December 31, 2010 and 2009, respectively. This decrease in 

stock-based compensation expense was due primarily to the decision in March 2009 to pay the 2008 management bonuses of $801,000 in vested 

restricted common shares in lieu of cash. Excluding stock-based compensation expense, general and administrative expense decreased $229,000 to 

$11.8 million for the year ended December 31, 2010 compared to $12.1 million for the year ended December 31, 2009. This decrease was primarily 

due to a $1.1 million decrease in bonus expense due to a one-time bonus paid in 2009 in conjunction with the sale of our Australian assets and a 

$1.3 million decrease in contract labor expense offset by higher legal costs of $1.5 million related to litigation matters and the payment of 2008 

management bonuses in restricted common shares rather than in cash. 

Litigation settlement expense. We reported litigation settlement expense of $21.7 million for the twelve months ended December 31, 2010 

primarily resulting from our settlement with the plaintiffs of the seven ClassicStar Mare Lease Litigation suits in December 2010 (for additional 

information regarding the settlement of this matter, as well as our other significant currently outstanding legal proceedings, see Note 15, 

“Commitments and Contingencies Litigation,” to our consolidated financial statements included in this Form 10-K). 

Interest expense. We reported interest expense of $150,000 for the year ended December 31, 2010 compared to $4.0 million for the year 

ended December 31, 2009. Interest expense excludes $633,000 and $10.8 million of capitalized interest in 2010 and 2009, respectively, which 

related to capital expenditures for undeveloped projects in East Texas, West Virginia and southwestern Pennsylvania. Excluding capitalized 

interest, interest expense decreased $14.8 million from December 31, 2009 to December 31, 2010 due to the payoff of substantially all outstanding 

debt in conjunction with the sale of our Australian assets in July 2009. 

Early extinguishment of debt. We did not record early extinguishment of debt expense for the year ended December 31, 2010. In conjunction 

with the repayment of our previous revolving credit facility, the term loan and the 12 3 / 4 % senior secured notes during 2009, we reported debt 

extinguishment expense of $15.9 million for the year ended December 31, 2009, comprised of $8.9 million of early prepayment penalty on the term 

loan and the 12 3 / 4 % senior secured notes and $7.0 million of unamortized deferred financing costs on the debt retired. 

Gain on sale of unproved properties. We did not record a gain on sale of assets for the year ended December 31, 2010. In July 2009, we sold

our non-producing Australian assets, for approximately $250.4 million, including gross reserve certification target proceeds and before transaction 

costs of approximately $1.5 million, resulting in a pre-tax gain on sale of $211.2 million for the year ended December 31, 2009. 

Warrant derivative loss. For the year ended December 31, 2010, we reported a $205,000 unrealized gain related to the fair value measurement 

of our warrants outstanding compared to a $205,000 unrealized loss at December 31, 2009. 

Foreign transaction gain (loss). We reported a foreign transaction gain of $353,000 for the year ended December 31, 2010 compared to a 

gain of $3.8 million for the year ended December 31, 2009. The decrease in foreign transaction gain was primarily due to Australian exchange rate 

fluctuations and a decrease in our Australian denominated cash and accounts receivable balances arising from the sale of our Australian assets in 

2009. 

Provision for income tax expense (benefit). We reported $804,000 of income tax benefit for the year ended December 31, 2010 compared to 

$70.3 million of income tax expense related to the gain on the sale of our Australian assets for the year ended December 31, 2009. The income tax 

benefit for the twelve months ended December 31, 2010 is primarily due to a $1.0 million downward adjustment of the tax expense related to the 

sale of our Australian assets after final review from the Australian Tax Office partially offset by withholding tax on the interest income earned from 

the Australian term deposit and a benefit for previously accrued state income taxes. At maturity on June 1, 2010, the term deposit was used to settle 

the tax liability resulting from the 2009 sale of our Australian assets. 

44 
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Index to Financial Statements 

Liquidity and Capital Resources 

Overview. Our primary sources of liquidity and capital resources are internally generated cash flows from operating activities or asset sales, 

availability under the Revolving Credit Facility, issuances of Gastar USA preferred equity and access to capital markets, to the extent available. In 

addition, during 2011, our Atinum Joint Venture provided a cash source for our Marcellus Shale development program by providing carried interest 

funding of $40.0 million of our share of drilling and completion costs on joint venture wells. 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. 

For the year ended December 31, 2011, we reported cash flow provided by operating activities of $10.2 million, net cash used in investing 

activities of $ 63.8 million, primarily for the development and purchase of natural gas and oil properties and net cash provided by financing 

activities of $ 56.8 million. As a result of these activities, our cash and cash equivalents balance increased by $ 3.2 million, resulting in a 

December 31, 2011 balance of cash and cash equivalents of $ 10.6 million. Net cash provided by operating activities increased $16.3 million from 

2010 primarily due to the litigation settlement expense of $18.6 million in 2010 and increased natural gas, oil and NGLs revenues in 2011 resulting 

from higher realized natural gas and oil prices including the effects of realized hedging. Cash flow used in investing activities increased $20.2 

million primarily due to increased development and purchase of natural gas and oil properties during 2011. During 2011, our financing activities 

primarily related to $30.0 million of net borrowings under the Revolving Credit Facility and proceeds from the issuance of 1,364,543 shares of 

Gastar USA's Series A Preferred Stock for net proceeds of $ 27.4 million. 

At December 31, 2011, we had a net working capital deficit of approximately $17.9 million, including $ 19.5 million of advances from nonoperators, of which $1.5 million will be applied to our net future costs pursuant to the carried interest provisions of the Atinum Joint Venture. At 

December 31, 2011, availability under the Revolving Credit Facility was $20.0 million. On March 5, 2012, Gastar USA received notification from 

its lenders that, effective immediately, the borrowing base under the Revolving Credit Facility was increased from $50.0 million to $100.0 million 

resulting in current availability under the Revolving Credit Facility of $73.0 million. 

Future capital and other expenditure requirements. Capital expenditures for 2012, excluding acquisitions, are projected to be approximately 

$134.2 million. In the Marcellus Shale, we expect to spend $103.0 million for drilling, completion, infrastructure, lease acquisition and seismic 

costs. We have budgeted $6.6 million for East Texas. In addition, we have allocated $19.8 million for a new Mid-Continent oil-focused venture and 

$4.8 million for capitalized interest and other costs. We plan on funding this capital activity through existing cash balances, internally generated 

cash flow from operating activities, borrowings under the Revolving Credit Facility and possible future ATM issuances of Gastar USA Series A 

Preferred Stock. Our capital expenditures and the scope of our drilling activities may change as a result of several factors, including, but not limited 

to, changes in natural gas and oil prices, costs of drilling and completion and leasehold acquisitions, drilling results, future ATM issuances of Gastar 

USA Series A Preferred Stock and changes in the borrowing base under the Revolving Credit Facility. 

Commodity Hedging Activities. Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices 

for natural gas. Prices for these commodities are determined primarily by prevailing market conditions including national and worldwide economic 

activity, weather, infrastructure capacity to reach markets, supply levels and other variable factors. These factors are beyond our control and are 

difficult to predict. 

To mitigate some of the potential negative impact on cash flow caused by changes in natural gas prices, we have entered into financial 

commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge natural gas price risk. In addition to 

NYMEX swaps and collars and fixed price swaps, we have also entered into basis only swaps. With a basis only swap, we have hedged the 

difference between the NYMEX price and the price received for our natural gas production at the specific delivery location. As of December 31, 

2011, the following derivative transactions were outstanding with the associated notational volumes and weighted average underlying hedge prices: 

 

45 
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Index to Financial Statements 

 _______________ 

At December 31, 2011, the estimated fair value of all of our commodity derivative instruments was a net asset of $15.9 million, comprised of 

current and non-current assets and liabilities. In conjunction with certain derivative hedging activity, we deferred the payment of certain put 

premiums for the production month period July 2010 through December 2012. At December 31, 2011, we had a current commodity derivative 

premium payable of $ 4.7 million. The put premium liabilities are payable monthly as the hedge production month becomes the prompt production 

month. 

By removing the price volatility from a portion of our natural gas for 2011, 2012, 2013 and 2014, we have mitigated, but not eliminated, the 

potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, 

certain derivative contracts also limit the benefits we could receive from increases in commodity prices. For additional information on the impact of 

changing prices on our financial position, see “Item 7A. Quantitative and Qualitative Disclosure about Market Risk”. 

As of December 31, 2011, all of our economic derivative hedge positions were with a multinational energy company or large financial 

institutions, which are not known to us to be in default on their derivative positions. Credit support for our open derivatives at December 31, 2011 is 

provided under the revolving credit facility through intercreditor agreements or open credit accounts of up to $5.0 million. We are exposed to credit 

risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, we do not anticipate nonperformance by such counterparties. 

Subsequent to December 31, 2011, we entered into additional fixed price swaps to mitigate future oil and NGLs price risk on a portion of our 

projected 2012 and 2013 production. For the period March to December 2012, we have fixed price swaps for 600 Bbls/d of crude oil at $102.01 per 

Bbl and 200 Bbls/d of NGLs at $52.50 per Bbl. For the calendar year 2013, we have fixed price swaps for 400 Bbls/d of crude oil at $100.75 per 

Bbl and 200 Bbls/d of NGLs at $52.50 per Bbl. 

Revolving Credit Facility . On October 28, 2009, we executed an amended and restated revolving credit facility, amending and restating in its 

entirety the original revolving credit facility (the "Revolving Credit Facility"). The Revolving Credit Facility now matures on September 30, 2015. 

At December 31, 2011, $ 30.0 million was outstanding under the Revolving Credit Facility. Effective March 5, 2012, the borrowing base under the 

Revolving Credit Facility was increased from $50.0 million to $100.0 million resulting in current availability of $73.0 million as of March 6, 2012. 

The borrowing base is typically subject to scheduled redeterminations on the first day of May and the first day of November each year prior to 

scheduled facility maturity. We have requested that our May 2012 redetermination be accelerated to be completed as of March 2012. The next 

regularly scheduled borrowing base redetermination will be November 2012. However, we and the lenders may request one additional unscheduled 

redetermination annually. The redetermination in November 2011 resulted in the Fourth Amendment to the Amended and Restated Credit 

Agreement, effective November 10, 2011, which resulted in, among other things, an extension of the maturity date for the facility from January 2, 

2013 to September 30, 2015 and the ability of Gastar USA to hedge up to 100% of the proved developed producing reserves reflected in 

46 

Settlement Period 

Derivative 

Instrument 

Average 

Daily 

Volume 

Total of 

Notional 

Volume 

Base 

Fixed 

Price 

Floor 

(Long) 

Short 

Put 

Ceiling 

(Short) 

 (in MMBtu’s) 

2012 Put spread 13,028 4,770,420 $ — $ 6.00 $ 4.05 $ —

2012 Costless three-way collar 7,410 2,711,580 — 5.73 4.00 6.88 

2012 (1) Call spread 2,000 550,000 — — — 4.50 

2012 Basis - HSC (2) 5,000 1,830,000 (0.08 ) — — —

2012 Basis - CIG (3) 500 183,000 (0.19 ) — — —

2013 Call spread 2,500 912,500 — — — 5.25 

2013 Costless three-way collar 2,500 912,500 — 5 4 6.45 

2013 Protective spread 2,500 912,500 5.44 — 3.79 —

2013 Fixed price swap 5,500 2,007,500 4.67 — — —

2013 Basis - HSC (2) 4,000 1,460,000 (0.11 ) — — —

2013 Basis - CIG (3) 650 237,250 (0.21 ) — — —

2014 Short calls 2,500 912,500 — — — 6.00 

(1) For the period April to December 2012 

(2) East Houston-Katy – Houston Ship Channel 

(3) Inside FERC Colorado Interstate Gas, Rocky Mountains 
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its reserve report using hedging other than floors and protective spreads. Pursuant to the Revolving Credit Facility, the applicable interest rate 

margin varies from 1.0% to 2.0% in the case of borrowings based on the prime rate and from 2.5% to 3.5% in the case of borrowings based on 

LIBO rate, depending on the utilization percentage in relation to the borrowing base. Under the Revolving Credit Facility, we are subject to certain 

financial covenants, including interest coverage ratio, a total net indebtedness to EBITDA ratio and current ratio requirement, and a limitation on 

our hedge positions. 

At December 31, 2011, Gastar USA was not in compliance with the current ratio covenant under the Revolving Credit Facility. Gastar USA 

was granted a waiver in regards to the current ratio at December 31, 2011 and in conjunction with such waiver, Gastar USA was in compliance with 

all financial covenants under the Revolving Credit Facility at December 31, 2011. Gastar USA does not anticipate any issues with current ratio 

compliance in the future. See Note 5, “Long Term Debt – Revolving Credit Facility.” 

Off-Balance Sheet Arrangements 

As of December 31, 2011, we had no off-balance sheet arrangements. We have no plans to enter into any off balance sheet arrangements in 

the foreseeable future. 

Contractual Obligations 

The following table summarizes our future contractual obligations as of December 31, 2011: 

 

_______________ 

We maintain a liability for costs associated with the retirement of tangible long-lived assets. At December 31, 2011, our reserve for these 

obligations totaled $ 8.3 million for which no contractual commitment exists. Information about this liability is set forth in Item 8. “Financial 

Statements and Supplementary Data, Note 2, Summary of Significant Accounting Policies – Asset Retirement Obligation” of this Form 10-K. 

We have employment agreements with our Chief Executive Officer and Chief Financial 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” of this Form 10-K. 

Commitments 

47 

 Payments Due by Period 

 Total 2012 2013 2014 2015 2016 Thereafter 

 (in thousands) 

Long-term debt (1) $ 30,000 $ — $ — $ — $ 30,000 $ — $ —

Interest on long-term debt (2) 3,697 986 986 986 739 — —

Deferred put premiums (3) 4,725 4,725 — — — — —

Office space leases (4) 2,270 495 498 509 459 309 —

Gathering system (5) 10,178 3,749 3,513 2,916 — — —

Office equipment leases 111 42 36 32 1 — —

Drilling rigs 4,970 4,970 — — — — —

Litigation settlement note payable 800 800 — — — — —

Total contractual obligations $ 56,751 

 $ 15,767  $ 5,033  $ 4,443  $ 31,199  $ 309  $ —

(1) See Note 5, "Long-Term Debt", to our consolidated financial statements included in this Form 10-K for a discussion of our revolving credit 

facility. 

(2) Interest payments have been calculated by applying the weighted average interest rate of 3.29% at December 31, 2011 to the outstanding longterm debt of $30.0 million at December 31, 2011. 

(3) In conjunction with certain derivative hedging activity, we deferred the payment of certain put premiums for the production month period 

January to December 2012. The put premium liabilities become payable monthly as the hedge production month becomes the prompt 

production month. 

(4) Houston office lease obligation expires August 31, 2016, and our West Virginia office lease commenced in December 2010 and expires on 

December 31, 2014. 

(5) Represents the minimum contractual gross daily volume commitment of 50,000 Mcf (35,000 net) per day for the period January 1, 2012 

through October 31, 2014 relating to the sale of our Hilltop gathering system. 
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In March 2008, we entered into the ETC Contract. The ETC Contract expires September 1, 2017. Pursuant to the ETC Contract, ETC 

currently provides us with 50 MMcf per day of treating capacity and 150 MMcf per day of transportation capacity from our Hilltop wells, located in 

Leon and Robertson Counties, Texas. 

On November 16, 2009, concurrent with our sale of the Hilltop gathering system in East Texas, one of our wholly-owned subsidiaries entered 

into a gas gathering agreement, with Hilltop Resort for a term of fifteen years. The agreement covers delivery of our gross production of natural gas 

from the Hilltop area of East Texas to certain delivery points provided under the ETC Contract as well as additional delivery points that may be 

added. We are also obligated to connect new wells that we drill within the area covered by the agreement to the gathering system. The agreement 

provides for a minimum quarterly gathering gross production volume of 50.0 MMcf per day (35.0 MMcf per day net to us) times the number of 

days in the quarter for five years from the effective date of November 1, 2009. If quarterly production is less than the minimum quarterly 

requirement, the gathering fee is payable on such deficit. If excess quarterly production exists, such excess is carried forward to offset any future 

deficit quarters. The gathering fee on the initial gross 25.0 Bcf of production is $0.325 per Mcf, reducing in steps to $0.225 per Mcf when 

cumulative gross production reaches 300.0 Bcf. The current gathering rate is $0.30 per Mcf. For the years ended December 31, 2011, 2010 and 

2009, we paid $1.5 million, $1.3 million and $78,000, respectively, of charges to Hilltop Resort as a result of actual production volumes being less 

than minimum contractual volume requirements. We do not expect that we will meet our minimum quarterly requirements in the near future. 

During December 2010, we, along with Atinum, entered into a gas purchase agreement with SEI with respect to our Marshall County, West 

Virginia production. The initial term of the gas purchase agreement is five years with the option to extend the term of the gas purchase agreement 

for an additional five year period. Our Marshall County, West Virginia production is dedicated to SEI for the term of the gas purchase agreement. 

SEI will purchase all hydrocarbon production, including its 120.0 MMcf per day Fort Beeler processing plant located in Marshall County, West 

Virginia for transporting and processing. In order to secure access to the Caiman facilities, we, Atinum and SEI dedicated all hydrocarbons 

purchased and produced in Marshall County, West Virginia for a term of ten years. 

Critical Accounting Policies and Estimates 

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which 

have been prepared in accordance with U.S. GAAP. The preparation of these financial statements requires management to make estimates and 

assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, related disclosure of contingent assets and liabilities, proved 

natural gas and oil reserves and the related disclosures in the accompanying consolidated financial statements. Certain accounting policies involve 

judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under 

different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our 

estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which 

form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual 

results may differ from these estimates and assumptions used in preparation of our financial statements. Below, we have provided an expanded 

discussion of our more significant accounting policies, estimates and judgments for our financial statements. We believe these accounting policies 

reflect the more significant estimates and assumptions used in preparation of the 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 or policy 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 whether or not the activities to 

which they apply are successful. Currently, our only cost center is the U.S. These 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 

48 

• 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. 
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Index to Financial Statements 

development activities. Capitalized costs also include salaries, employee benefits, costs of consulting services and other expenses that directly relate 

to our natural gas and oil activities. Interest costs related to unproved properties are also capitalized. Costs associated with production and general 

corporate activities are expensed in the period incurred. The capitalized costs of our natural gas and oil properties, plus an estimate of our future 

development and abandonment costs, are amortized on a unit-of-production method based on our estimate of total 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 to determine depletion expense for the period. 

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. 

Our financial position and results of operations would have been significantly different had we used the successful efforts method of 

accounting for our oil and gas activities, since we generally reflect a higher level of capitalized costs as well as a higher DD&A rate on our oil and 

natural gas properties. 

Full Cost Ceiling Limitation 

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 present value of estimated future cash flow from proved natural gas and oil reserves 

reduced by future operating expenses, development expenditures, abandonment costs (net of salvage) to the extent not included in natural gas and 

oil properties pursuant to authoritative guidance and estimated future income taxes thereon. 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. The ceiling calculation dictates that the 12-month 

unweighted arithmetic average of the first-day-of-the-month prices and costs in effect are held constant indefinitely. 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 historical 

average prices and costs in effect at the time of the evaluation. 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. 

In 2011, the key natural gas prices utilized were the Henry Hub price of $ 4.12 per MMBtu, the Katy Hub price of $ 4.07 per MMBtu, the 

CIG price of $ 3.93 per MMBtu, the Columbia Gas Appalachia Pool price of $ 4.20 per MMBtu and an oil price of $ 92.71 per barrel. In applying 

the full cost method at December 31, 2011 and 2010, we performed a 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”), was limited to the sum of the estimated future net revenues from our proved 

reserves using the 12-month unweighted arithmetic average of the first-day-of-the-month prices for natural gas and oil held constant, discounted at 

10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects and we did not record a ceiling impairment 

for the years ended December 31, 2011 and 2010. A ceiling impairment of $68.7 million was required at December 31, 2009 based on the results of 

the December 31, 2009 ceiling test calculation. 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 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 reduced our 

ceiling impairment cushion by approximately $29.6 million resulting in an impairment of $18.1 million. A 10% increase in prices would have 

increased our ceiling impairment cushion by approximately $26.5 million. 

Natural Gas and Oil Reserves 

All of the reserves data in this Form 10-K are estimates. Estimates of our natural gas and oil reserves were prepared in accordance with 

guidelines established by the SEC. 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. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are 

numerous uncertainties inherent in estimating quantities of proved natural gas and oil reserves. Uncertainties include the projection of future 

production rates and the expected timing of 

49 
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Index to Financial Statements 

development expenditures. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological 

interpretation and judgment. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs 

and workover costs, all of which may 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. As a result, reserves estimates may be different from the 

quantities of natural gas and oil that are ultimately recovered. 

In addition, economic producibility of reserves is dependent on the natural gas and oil prices used in the reserves estimate. We based our 

December 31, 2011 reserves estimates on a 12-month unweighted average of the first-day-of-the month prices, in accordance with SEC rules. 

However, natural gas and oil prices are volatile and, as a result, our reserves estimates will change in the future. Despite the inherent imprecision in 

these engineering estimates, our proved reserve volumes and values are used to calculate depletion and impairment provisions. 

Depreciation, Depletion and Amortization 

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. A 10% increase in reserves would have decreased our depletion expense for the year ended December 31, 2011 by approximately $383,000, 

while a 10% decrease in reserves would have increased our depletion expense by approximately $467,000. 

Unproved Property Costs 

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. 

At December 31, 2011, we had $ 78.3 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 to determine 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. A 10% increase or decrease in the unproved 

property balance would have increased or decreased our impairment cushion by approximately $7.3 million, respectively, for the year ended 

December 31, 2011. 

Asset Retirement Obligation 

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. Pursuant to the FASB’s guidance, we estimate 

asset retirement costs for all of our assets, inflation-adjust those costs to the forecasted abandonment date, discount that amount using a creditadjusted-risk-free rate back to the date we acquired the asset or obligation to retire the asset and record an asset retirement obligation (“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 ARO 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. 

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. 

There are many variables in estimating AROs. We primarily use the remaining estimated useful life from the year-end 

50 
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Index to Financial Statements 

independent reserves report in estimating when abandonment could be expected for each property based on field or industry practices. We expect to 

see our calculations impacted significantly if interest rates move from their current levels, as the credit-adjusted-risk-free rate is one of the variables 

used on a quarterly basis. Our technical team developed a standard cost estimate based on historical costs, industry quotes and depth of wells. 

Unless we expect a well’s plugging cost to be significantly different than a normal abandonment, we use this estimate. The resulting estimate, after 

application of an inflation factor and a discount factor, could differ from actual results, despite all of our efforts to make an accurate estimate. 

Capitalized Interest 

We capitalize interest on assets not being amortized, such as our drilling in progress expenditures and unproven natural gas and oil properties. 

The methodology for capitalizing interest on general funds 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 drilling and 

unproved property expenditures 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. Currently, we only capitalize interest on the Revolving Credit Facility. 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. Capitalized interest was approximately $817,000, 

$633,000 and $10.8 million for 2011, 2010 and 2009, respectively. 

Stock-Based Compensation 

We report compensation expense for stock options and restricted common shares granted to officers, directors and employees using the fair 

value method and recognition provisions of the modified prospective method. 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 BlackScholes-Merton valuation pricing model. The fair value of restricted common shares granted is equal to the closing price on the day prior to the 

grant. 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. 

The Black-Scholes-Merton valuation pricing 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 valuation pricing model change significantly, stock-based 

compensation expense may differ materially in the future from that recorded in the current period. There were no stock options granted during the 

year ended December 31, 2011. 

Fair Value Measurement 

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, basis and fixed price swaps and put and call options to hedge 

commodity price risk. We carry all derivative assets and liabilities at fair value. 

We determine the fair market values of financial instruments based on the fair value hierarchy established by the FASB. 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. 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. 

Derivative Instruments and Hedging Activity 

We currently utilize derivative instruments, which are placed with a multinational energy company or large financial institutions, to manage 

market risks resulting from fluctuations in commodity prices of natural gas and oil. Derivatives are recorded on the balance sheet at fair market 

value and changes in the fair market value of derivatives are recorded each period in current earnings. Gains and losses on derivatives are included 

in revenue in the period in which they occur. The resulting cash flows from derivatives are reported as cash flows from operating activities. 

The counterparties to our derivative instruments are not known to be in default on their derivative positions. However, we are exposed to 

credit risk to the extent of nonperformance by the counterparty in the derivative contracts. We believe credit risk is minimal and do not anticipate 

such nonperformance by such counterparties. 

51 
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Recent Accounting Developments 

The following recently issued accounting pronouncements have been adopted or may impact the Company in future periods: 

Comprehensive Income. In June 2011, the FASB issued an amendment to previously issued guidance regarding the reporting and 

presentation of other comprehensive income. The amendments require that all non-owner changes in stockholders’ equity be presented either in a 

single continuous statement of comprehensive income or in two separate but consecutive statements. In the two-statement approach, the first 

statement should present total net income and its components followed consecutively by a second statement that should present total other 

comprehensive income, the components of other comprehensive income and the total of comprehensive income. Regardless of whether an entity 

chooses to present comprehensive income in a single continuous statement or in two separate but consecutive statements, the entity is required to 

present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net 

income in the statement(s) where the components of net income and the components of other comprehensive income are presented. The 

amendments do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be 

reclassified to net income. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 

and should be applied retrospectively. Earlier application is permitted. The adoption of this guidance will not impact our operating results, financial 

position or cash flows. 

Fair Value Measurement. In May 2011, the FASB issued an amendment to previously issued guidance regarding fair value measurement 

and disclosure requirements. The amendments explain how to measure fair value and do not require additional fair value measurements and are not 

intended to establish valuation standards or affect valuation practices outside of financial reporting. The amendments result in common fair value 

measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. This guidance is effective prospectively 

for interim and annual periods beginning after December 15, 2011. Early application is not permitted. 

Business Combinations. In December 2010, the FASB's Emerging Issues Task Force (“EITF”) issued an amendment to previously issued 

guidance regarding the pro forma revenue and earnings disclosure requirements for business combinations. The amendments specify that if a public 

entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business 

combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The 

amendments also expand the supplemental pro forma disclosures under current guidance to include a description of the nature and amount of 

material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and 

earnings. This guidance is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first 

annual reporting period beginning on or after December 15, 2010. Earlier application is permitted. The adoption of this guidance did not impact our 

operating results, financial position or cash flows. 

Item 7A. Quantitative and Qualitative Disclosures about Market Risk 

Commodity Price Risk 

Our major commodity price risk exposure is to the prices received for our natural gas production. Realized commodity prices received for our 

production are the spot prices applicable to natural gas in the region produced. Prices received for natural gas are volatile and unpredictable and are 

beyond our control. For the year ended December 31, 2011, a 10% change in the prices received for natural gas production would have had an 

approximate $2.4 million impact on our revenues prior to hedge transactions to mitigate our commodity pricing risk. See Note 9, “Derivative 

Instruments and Hedging Activity.” 

Interest Rate Risk 

At December 31, 2011, we had $30.0 million outstanding under the Revolving Credit Facility. Based on the amount outstanding under our 

Revolving Credit Facility at December 31, 2011, a one percentage point change in the interest rate would have had a $75,000 impact on our interest 

expense, all of which would have been capitalized. We currently do not use interest rate derivatives to mitigate our exposure to the volatility in 

interest rates, including under the Revolving Credit Facility, as this risk is minimal. 

Foreign Currency Exchange Risk 

During 2009, we sold all of our Australian assets. As a result, all of our current and future revenues and capital expenditures and substantially 

all of our expenses are in U.S. dollars, thus limiting our exposure to foreign currency exchange risk. 

52 
Table of Contents 

Index to Financial Statements 

Item 8. Financial Statements and Supplementary Data

The reports of our independent registered public accounting firms and our consolidated financial statements, related notes and supplementary 

information are presented beginning on page F-1. 

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

Not applicable. 

Item 9A. Controls and Procedures 

Evaluation of Disclosure Controls and Procedures 

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our 

management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure 

controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-

K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in 

reports that we file under the Exchange Act 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. Our principal executive officer and principal financial officer have 

concluded that our current disclosure controls and procedures were effective as of December 31, 2011 at the reasonable assurance level. 

Management’s Report on Internal Control over Financial Reporting 

Our internal controls over financial reporting 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 SEC’s rules and 

forms. These internal controls over financial reporting include controls and procedures designed to ensure that information required to be disclosed 

under the Exchange Act is accumulated and communicated to our management on a timely basis to allow decisions regarding required disclosure. 

Under the supervision and with the participation of our management, including our chief executive officer, chief financial officer and chief 

accounting officer, we evaluated the effectiveness of the design and operation of our internal controls over financial reporting as of December 31, 

2011 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. 

Based on the assessment, our management has concluded that our internal control over financial reporting was effective as of December 31, 

2011 based on the criteria listed herein. 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 USA, LLP, an independent registered public accounting firm, as stated 

in their report which is included herein. 

 

Changes in Internal Control over Financial Reporting 

53 

/s/ J. RUSSELL PORTER /s/ MICHAEL A. GERLICH 

J. Russell Porter Michael A. Gerlich 

President and Chief Executive Officer Vice President and Chief Financial Officer 

March 8, 2012 March 8, 2012 
Table of Contents 

Index to Financial Statements 

During the fourth quarter of 2011, 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. 

54 
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, 2011, 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, 2011, 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, 2011 and 2010 and the related consolidated statements of operations, 

stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011 and our report dated March 8, 2012 

expressed an unqualified opinion thereon. 

/s/ BDO USA, LLP 

Dallas, Texas 

March 8, 2012 

55 
Table of Contents 

Index to Financial Statements 

Item 9B. Other Information 

None. 

PART III 

Item 10. Directors and Executive Officers and Corporate Governance 

The information regarding directors, executive officers, promoters and control persons required under Item 10 of Form 10-K will be 

contained in our Definitive Proxy Statement for our 2012 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, 2011. 

Item 11. Executive Compensation 

The information required under Item 11 of Form 10-K will be contained in the Proxy Statement under the heading “Executive Compensation”

and is incorporated herein by reference. 

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

The information required under Item 12 of Form 10-K will be contained in the Proxy Statement under the heading “Security Ownership of 

Certain Beneficial Owners and Management” and is incorporated herein by reference. 

Item 13. Certain Relationships and Related Transactions and Director Independence 

The information required under Item 13 of Form 10-K will be contained in the Proxy Statement under the heading “Committee Information” 

and is incorporated herein by reference. 

Item 14. Principal Accountant Fees and Services 

The information required under Item 14 of Form 10-K will be contained in the Proxy Statement under the heading “Independent Accountant, 

Fees and Policies” and is incorporated herein by reference. 

PART IV 

Item 15. Exhibits, 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. 

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 

(a)-1 Financial Statements and Schedules: 

(b) Exhibits: 

Exhibit Number Description 

3.1 

 

Amended and Restated Articles of Incorporation of Gastar Exploration Ltd. (incorporated herein by reference to Exhibit 3.1 to 

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

127498). 

 

3.2 

 

Amended Bylaws of Gastar Exploration Ltd. dated as of June 3, 2010 (incorporated herein by reference to Exhibit 3.1 of the 

Company’s Current Report on Form 8-K dated June 4, 2010. File No. 001-32714). 

 

3.3 

 

Articles of Amendment and Share Structure attached to and forming part of the Amended and Restated Articles of 

Incorporation of Gastar Exploration Ltd., dated as of June 30, 2009 (incorporated by reference to Exhibit 3.1 of the Company’s 

Current Report on Form 8-K dated July 1, 2009. File No. 001-32714). 

Table of Contents 

Index to Financial Statements 

Exhibit Number Description 

 

3.4 

 

Articles of Amendment attached to and forming part of the Amended and Restated Articles of Incorporation of Gastar 

Exploration Ltd, dated as of July 23, 2009 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 

8-K dated July 24, 2009. File No. 001-32714). 

 

3.5 

 

Certificate of Incorporation of Gastar Exploration USA, Inc. (incorporated by reference to Exhibit 3.3 to Gastar Exploration 

USA, Inc.'s Registration Statement on Form S-3, dated May 27, 2011. Registration No. 333-174552). 

 

3.6 

 

Amended and Restated Bylaws of Gastar Exploration USA, Inc. (incorporated by reference to Exhibit 3.3 to Gastar Exploration 

USA, Inc.'s Registration Statement on Form S-3, dated May 27, 2011. Registration No. 333-174552). 

 

3.7 

 

Certificate of Designation of Rights and Preferences of 8.625% Series A Cumulative Preferred Stock (incorporated by 

reference to Exhibit 3.3 of Gastar Exploration USA, Inc.'s Form 8A filed on June 20, 2011). 

 

4.1 

 

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). 

 

10.1 

 

Amended and Restated Credit Amendment dated October 28, 2009 to 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 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated 

November 3, 2009. File No. 001-32714). 

10.2 

 

Consent and First Amendment to Amended and Restated Credit Agreement dated November 20, 2009, by and among Gastar 

Exploration USA, Inc., the Guarantors party thereto, the Lenders party thereto, and Amegy Bank National Association, as 

Administrative Agent, (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K dated 

November 25, 2009. File No. 001-32714). 

 

10.3 

 

Second Amendment to Amended and Restated Credit Agreement dated June 24, 2010, by and among Gastar Exploration USA, 

Inc., the Guarantors party thereto, the Lenders party thereto and Amegy Bank National Association, as Administrative Agent 

(incorporated herein by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K dated June 28, 2010. File No. 

001-32714). 

 

10.4 

 

Third Amendment to Amended and Restated Credit Agreement, dated June 14, 2011, by and among Gastar Exploration USA, 

Inc., the Guarantors party thereto, the Lenders party thereto and Amegy Bank National Association, as Administrative Agent 

(incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K dated June 15, 2011. File No. 001-

32714). 

 

10.5 

 

Fourth Amendment to Amended and Restated Credit Agreement, effective November 10, 2011, by and among Gastar 

Exploration USA, Inc., the Guarantors party thereto, the Lenders party thereto and Amegy Bank National Association, as 

Administrative Agent (incorporated by reference to Exhibit 10.5 of the Company’s Current Report on Form 8-K dated 

December 2, 2011. File No. 001-32714). 

 

10.6 

 

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. File No. 001-32714). 

 

10.7 

 

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). 

 

10.8 

 

Sale Agreement dated July 2, 2009, by and among Gastar Exploration USA, Inc., Gastar Exploration New South Wales, Inc., 

Santos QNT Pty Ltd. and Santos International Holdings Pty Ltd. (incorporated herein by reference to Exhibit 10.1 to Gastar 

Exploration Ltd.’s Current Report on Form 8-K filed on August 6, 2009. File No. 001-32714). 

 

10.9 

 

Agency Agreement between and among ETC Texas Pipeline, Ltd., ETC Katy Pipeline, Ltd. Oasis Pipeline, L.P. and Gastar 

Exploration Texas, L.P. effective September 1, 2007 (incorporated herein by reference to Exhibit 10.1 of the Amendment No. 1 

to the Company’s Annual Report on Form 10-K/A for the fiscal year ended December 31, 2008 filed on October 20, 2009. File 

No. 001-32714). 
57 

 

10.10 

 

Gas Gathering Agreement between Gastar Exploration Texas, LP, as Seller, and Hilltop Resort GS, LLC, as Buyer, dated 

November 16, 2009 and effective as of November 1, 2009 (incorporated by reference to Exhibit 10.1 of the Company’s Current 

Report on Form 8-K dated November 20, 2009. File No. 001-32714). 

 
Table of Contents 

Index to Financial Statements 

Exhibit Number Description 

10.11 

 

Purchase and Sale Agreement between Gastar Exploration Texas, LP, as Seller, and Hilltop Resort GS, LLC, as Buyer, dated 

November 16, 2009 (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K dated November 

20, 2009. File No. 001-32714). 

 

10.12 

 

Purchase and Sale Agreement between Gastar Exploration Texas, LP, as Seller, and Navasota Resources LTD., LLP, as Buyer, 

dated November 16, 2009 (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K dated 

November 20, 2009. File No. 001-32714). 

 

10.13 

 

Purchase and Sale Agreement between Gastar Exploration Texas, LP, as Seller, and Presco, Inc., as Buyer, dated November 16, 

2009 (incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K dated November 20, 2009. File 

No. 001-32714). 

 

10.14 

 

Purchase and Sale Agreement, dated September 21, 2010, by and between Gastar Exploration USA, Inc. and Atinum Marcellus 

I LLC (incorporated herein by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K dated September 24, 

2010. File No. 001-32714). 

 

10.15 

 

Form of Participation Agreement (incorporated herein by reference to Exhibit 2.2 of the Company’s Current Report on Form 8-

K dated September 24, 2010. File No. 001-32714). 

 

10.16 

 

Form of the Final Settlement Agreement and Comprehensive General Release between and among James D. Lyon, Chapter 7 

Trustee of ClassicStar LLC, Gastar Exploration Ltd., and other Individuals and Entities Set Forth Herein Effective November 

1, 2010 (incorporated herein by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated November 2, 

2010. File No. 001-32714). 

 

10.17 

 

Purchase and Sale Agreement, dated November 5, 2010, by and among MegaEnergy, Inc. and Saga Petroleum Corp. and 

Gastar Exploration USA, Inc. (incorporated herein by reference to Exhibit 10.1 on the Company’s Current Report on Form 8-K 

dated December 20, 2010. File No. 001-32714). 

 

10.18 

 

Guarantee Agreement, dated June 23, 2011, by and between Gastar Exploration Ltd. and Gastar Exploration USA, Inc. 

(incorporated by reference to Exhibit 10.1 of Gastar Exploration Ltd.'s Current Report on Form 8-K dated June 23, 2011. File 

No. 001-32714). 

 

10.19* 

 

Employment Agreement dated March 23, 2005 by and among First Sourcenergy Wyoming and Montana, Inc., Gastar 

Exploration Ltd. and J. Russell Porter (incorporated by reference to Exhibit 10.2 of the Company’s Registration Statement on 

Form S-1, filed on August 12, 2005. Registration No. 333-127498). 

 

10.20* 

 

First Amendment to Employment Agreement entered into by and between Gastar Exploration, Ltd, Gastar Exploration USA, 

Inc., f/k/a First Sourcenergy Wyoming and Montana, Inc., and J. Russell Porter as of July 25, 2008 (incorporated by reference 

to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated July 28, 2008. File No. 001-32714). 

 

10.21* 

 

Second Amendment to Employment Agreement entered into by and between Gastar Exploration Ltd., Gastar Exploration USA, 

Inc. and J. Russell Porter as of February 3, 2011 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report 

on Form 8-K dated February 7, 2011. File No. 001-32714). 

 

10.22* 

 

Employment Agreement dated April 26, 2005 by and among First Sourcenergy Wyoming and Montana, 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). 

 

10.23* 

 

First Amendment to Employment Agreement entered into by and between Gastar Exploration, Ltd, Gastar Exploration USA, 

Inc., f/k/a First Sourcenergy Wyoming and Montana, 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. File No. 001-32714). 

 

10.24* 

 

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). 

 

10.25* 

 

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). 
58 

 

10.26* 

 

First Amendment to Gastar Exploration Ltd. 2006 Long-Term Stock Incentive Plan, effective as of April 1, 2009, approved 

June 4, 2009 (incorporated by reference to Exhibit 10.2 of the Company’s Current Report of Form 8-K dated June 10, 2009. 

File No. 001-32714). 

 

10.27* 

 

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). 

 
Table of Contents 

Index to Financial Statements 

Exhibit Number Description 

10.28* 

 

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). 

 

10.29* 

 

Gastar Exploration Ltd. Annual Bonus Plan (incorporated by reference to Exhibit 10.1 of the Company's Current Report on 

Form 8-K dated August 8, 2011. File No. 001-32714). 

 

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 USA, LLP 

 

23.2† Consent of BDO USA, LLP 

 

23.3† Consent of Wright & Company, Inc. 

 

23.4† Consent of Netherland, Sewell & Associates, Inc. 

 

31.1† Certification of Chief Executive Officer of Gastar Exploration Ltd. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 

 

31.2† Certification of Chief Financial Officer of Gastar Exploration Ltd. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 

 

31.3† Certification of President of Gastar Exploration USA, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 

 

31.4† Certification of Treasurer of Gastar Exploration USA, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 

 

32.1†† Certification of Chief Executive Officer of Gastar Exploration Ltd. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 

 

32.2†† Certification of Chief Financial Officer of Gastar Exploration Ltd. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 

 

32.3†† Certification of President of Gastar Exploration USA, Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 

 

32.4†† Certification of Treasurer of Gastar Exploration USA, Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 

 

99.1†† Report of Netherland, Sewell & Associates, Inc. dated January 23, 2012. 

 

99.2†† Report of Wright & Company, Inc. dated January 19, 2012. 

 

101.INS†† XBRL Instance Document 

 

101.SCH†† XBRL Taxonomy Extension Schema Document 

 

101.CAL†† XBRL Taxonomy Extension Calculation Linkbase Document 

 

101.DEF†† XBRL Taxonomy Extension Definition Linkbase Document 

 

101.LAB†† XBRL Taxonomy Extension Label Linkbase Document 

 

101.PRE†† XBRL Taxonomy Extension Presentation Linkbase Document 
59 

* Management contract or compensatory plan or arrangement. 

† Filed herewith. 

†† Furnished herewith. 
Table of Contents 

Index to Financial Statements 

SIGNATURES 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be 

signed on its behalf by the undersigned, thereunto duly authorized. 

GASTAR EXPLORATION LTD. 

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of 

the registrant and in the capacities and on the dates indicated. 

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be 

signed on its behalf by the undersigned, thereunto duly authorized. 

GASTAR EXPLORATION USA, INC. 

 

/s/ J. RUSSELL PORTER 

J. Russell Porter, President and Chief Executive 

Officer 

(Duly authorized officer and principal executive 

officer) 

March 8, 2012 

Name Title Date 

 

/s/ J. RUSSELL PORTER President, Chief Executive Officer, Chief Operating Officer 

(principal executive officer) and Director 

 March 8, 2012 

J. Russell Porter 

 

/s/ MICHAEL A. GERLICH Vice President and Chief Financial Officer (principal financial 

and accounting officer) 

 March 8, 2012 

Michael A. Gerlich 

 

/s/ FLOYD R. PRICE Chairman of the Board March 8, 2012 

Floyd R. Price 

 

/s/ JOHN H. CASSELS Director March 8, 2012 

John H. Cassels 

 

/s/ RANDOLPH C. COLEY Director March 8, 2012 

Randolph C. Coley 

 

/s/ ROBERT D. PENNER Director March 8, 2012 

Robert D. Penner 

 

/s/ JOHN M. SELSER SR. Director March 8, 2012 

John M. Selser Sr. 

/s/ J. RUSSELL PORTER 

J. Russell Porter, President 

(Duly authorized officer and principal executive 

officer) 

March 8, 2012 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of 

the registrant and in the capacities and on the dates indicated. 

60 
Table of Contents 

Index to Financial Statements 

61 

Name Title Date 

 

/s/ J. RUSSELL PORTER President and Sole Director March 8, 2012 

J. Russell Porter 

 

/s/ MICHAEL A. GERLICH Secretary and Treasurer (principal financial and 

accounting officer) 

 March 8, 2012 

Michael A. Gerlich 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS 

 

F- 1 

 Page 

 

Reports of Independent Registered Public Accounting Firm F- 2 

 

Gastar Exploration Ltd. Consolidated Balance Sheets as of December 31, 2011 and 2010 F- 3 

 

Gastar Exploration Ltd. Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009 F- 5 

 

Gastar Exploration Ltd. Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2011, 2010 and 2009 F- 6 

 

Gastar Exploration Ltd. Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009 F- 7 

 

Gastar Exploration USA, Inc. Consolidated Balance Sheets as of December 31, 2011 and 2010 F- 8 

 

Gastar Exploration USA, Inc. Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009 F- 9 

 

Gastar Exploration USA, Inc. Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2011, 2010 and 

2009 

F- 10 

 

Gastar Exploration USA, Inc. Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009 F- 11 

 

Notes to Consolidated and Gastar Exploration USA, Inc. Financial Statements F- 12 
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, 2011 and 2010 and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years 

in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to 

express an opinion on these financial statements based on our audits. 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those 

standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material 

misstatement. 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 financial statement presentation. 

We believe that our audits provide a reasonable basis for our opinion. 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gastar 

Exploration Ltd. at December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended 

December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. 

As discussed in Note 9 to the consolidated financial statements, effective January 1, 2009, the Company changed its method of accounting for 

certain common stock purchase warrants with the adoption of new guidance on determining whether an instrument is indexed to an entity's own 

stock. As discussed in Note 2 to the consolidated financial statements, effective December 31, 2009, the Company changed its reserve estimates and 

related disclosures as a result of adopting new oil and natural gas reserve estimation and disclosure requirements. 

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, 2011, 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 8, 2012 

expressed an unqualified opinion thereon. 

/s/ BDO USA, LLP 

Dallas, Texas 

March 8, 2012 

F- 2 
Table of Contents 

Index to Financial Statements 

Report of Independent Registered Public Accounting Firm 

Board of Directors and Stockholders 

Gastar Exploration USA, Inc. 

Houston, Texas 

We have audited the accompanying consolidated balance sheets of Gastar Exploration USA, Inc. ("Gastar USA") and subsidiaries as of 

December 31, 2011 and 2010 and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years 

in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to 

express an opinion on these financial statements based on our audits. 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those 

standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material 

misstatement. 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 financial statement presentation. 

We believe that our audits provide a reasonable basis for our opinion. 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gastar 

Exploration USA, Inc. at December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period 

ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. 

As discussed in Note 9 to the consolidated financial statements, effective January 1, 2009, Gastar USA changed its method of accounting for 

certain common stock purchase warrants with the adoption of new guidance on determining whether an instrument is indexed to an entity's own 

stock. As discussed in Note 2 to the consolidated financial statements, effective December 31, 2009, the Company changed its reserve estimates and 

related disclosures as a result of adopting new oil and natural gas reserve estimation and disclosure requirements. 

/s/ BDO USA, LLP 

Dallas, Texas 

March 8, 2012 

F- 3 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

CONSOLIDATED BALANCE SHEETS 

 December 31, 

 2011 2010 

 (in thousands) 

ASSETS 

CURRENT ASSETS: 

Cash and cash equivalents $ 10,647 $ 7,439 

Accounts receivable, net of allowance for doubtful accounts of $551 and $571, respectively 10,706 4,034 

Commodity derivative contracts 19,385 10,229 

Prepaid expenses 1,243 1,191 

Total current assets 41,981 22,893 

PROPERTY, PLANT AND EQUIPMENT: 

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

Unproved properties, excluded from amortization 78,302 162,230 

Proved properties 514,357 345,042 

Total natural gas and oil properties 592,659 507,272 

Furniture and equipment 1,629 1,175 

Total property, plant and equipment 594,288 508,447 

Accumulated depreciation, depletion and amortization (308,548 ) (293,332 ) 

Total property, plant and equipment, net 285,740 215,115 

OTHER ASSETS: 

Restricted cash 50 50 

Commodity derivative contracts 4,130 8,482 

Deferred charges, net 535 508 

Advances to operators and other 2,067 304 

Total other assets 6,782 9,344 

TOTAL ASSETS $ 334,503 $ 247,352 

LIABILITIES AND SHAREHOLDERS’ EQUITY 

CURRENT LIABILITIES: 

Accounts payable $ 17,693 $ 8,294 

Revenue payable 4,137 4,331 

Accrued interest 144 138 

Accrued drilling and operating costs 4,647 1,490 

Advances from non-operators 19,523 783 

Commodity derivative contracts 6,479 1,991 

Commodity derivative premium payable 4,725 3,451 

Accrued litigation settlement liability 800 3,164 

Other accrued liabilities 1,723 2,024 

Total current liabilities 59,871 25,666 

LONG-TERM LIABILITIES: 

Long-term debt 30,000 —

Commodity derivative contracts 1,163 1,521 

Commodity derivative premium payable — 4,725 

Accrued litigation settlement liability — 800 

Asset retirement obligation 8,275 7,249 

Total long-term liabilities 39,438 14,295 

Commitments and contingencies (Note 15) 

SHAREHOLDERS’ EQUITY: 

Common stock, no par value; unlimited shares authorized; 64,706,750 and 64,179,115 shares issued and outstanding at December 31, 

2011 and 2010, respectively 316,346 316,346 

Additional paid-in capital 25,376 23,200 

Accumulated deficit (133,919 ) (132,155 ) 
The accompanying notes are an integral part of these consolidated financial statements. 

F- 4 

Total shareholders’ equity 207,803 207,391 

Non-controlling interest: 

Preferred stock of subsidiary, aggregate liquidation preference $34,114 at December 31, 2011 27,391 —

Total equity 235,194 207,391 

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $ 334,503 $ 247,352 
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- 5 

 Years Ended December 31, 

 2011 2010 2009 

 (in thousands, except share and per share data) 

REVENUES: 

Natural gas $ 33,391 $ 30,812 $ 40,407 

Oil 3,416 742 229 

NGLs 1,092 — —

Total natural gas, oil and NGLs revenues 37,899 31,554 40,636 

Unrealized natural gas hedge gain (loss) 2,336 11,214 (7,767 ) 

Total revenues 40,235 42,768 32,869 

EXPENSES: 

Production taxes 620 370 439 

Lease operating expenses 8,630 6,679 6,572 

Transportation, treating and gathering 4,501 4,654 1,547 

Depreciation, depletion and amortization 15,216 9,306 16,484 

Impairment of natural gas and oil properties — — 68,729 

Accretion of asset retirement obligation 534 396 379 

General and administrative expense 11,365 14,638 15,649 

Litigation settlement expense — 21,744 —

Total expenses 40,866 57,787 109,799 

LOSS FROM OPERATIONS (631 ) (15,019 ) (76,930 ) 

OTHER INCOME (EXPENSE): 

Interest expense (113 ) (150 ) (3,993 ) 

Early extinguishment of debt — — (15,902 ) 

Investment income and other 10 1,347 1,267 

Gain on sale of assets — — 211,162 

Unrealized warrant derivative gain (loss) — 205 (205 ) 

Foreign transaction (loss) gain (6 ) 353 3,764 

INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES (740 ) (13,264 ) 119,163 

Provision for income tax expense (benefit) — (804 ) 70,317 

NET INCOME (LOSS) $ (740 ) $ (12,460 ) $ 48,846 

Dividend on preferred stock attributable to non-controlling interest 1,024 — —

NET INCOME (LOSS) ATTRIBUTABLE TO GASTAR EXPLORATION LTD. $ (1,764 ) $ (12,460 ) $ 48,846 

 

NET INCOME (LOSS) PER COMMON SHARE ATTRIBUTABLE TO GASTAR EXPLORATION 

LTD. COMMON SHAREHOLDERS: 

Basic $ (0.03 ) $ (0.25 ) $ 1.06 

Diluted $ (0.03 ) $ (0.25 ) $ 1.06 

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: 

Basic 63,003,579 49,813,617 46,102,662 

Diluted 63,003,579 49,813,617 46,210,424 
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- 6 

 Common Stock Additional 

Paid-in 

Capital 

 

Accumulated 

Other 

Comprehensive 

Income (Loss) 

 

Accumulated 

Deficit 

 

Total Gastar 

Exploration Ltd. 

Shareholders’ 

Equity 

 Noncontrolling 

Interest 

 

 Shares Amount Total Equity 

 (in thousands, except share data) 

Balance at December 31, 2008 41,927,061 $ 249,980 $ 22,883 $ 2,648 $ (173,929 ) $ 101,582 $ — $ 101,582 

Cumulative effect of reclassification 

of warrants — — (5,388 ) — 5,388 — — —

Issuance of shares—cash, net of 

offering costs of $771 7,300,000 13,829 — — 13,829 — 13,829 

Issuance of restricted shares, net of 

forfeitures 801,531 — (260 ) — — (260 ) — (260 ) 

Stock based compensation — — 3,547 — — 3,547 — 3,547 

Comprehensive income: 

Commodity derivatives 

reclassified to earnings and 

other — — — (2,648 ) — (2,648 ) — (2,648 ) 

Net income — — — — 48,846 48,846 — 48,846 

Comprehensive income — — — — — 46,198 — 46,198 

Balance at December 31, 2009 50,028,592 263,809 20,782 — (119,695 ) 164,896 — 164,896 

Issuance of shares—cash, net of 

offering costs of $2,663 13,800,000 52,537 — — — 52,537 — 52,537 

Issuance of restricted shares, net of 

forfeitures 349,502 — (347 ) — — (347 ) — (347 ) 

Exercise of stock options, net of 

forfeitures 1,021 — — — — — — —

Stock based compensation — — 2,765 — — 2,765 — 2,765 

Comprehensive loss: 

Net loss — — — — (12,460 ) (12,460 ) — (12,460 ) 

Comprehensive loss — — — — — (12,460 ) — (12,460 ) 

Balance at December 31, 2010 64,179,115 316,346 23,200 — (132,155 ) 207,391 — 207,391 

Issuance of restricted shares, net of 

forfeitures 524,337 — (436 ) — — (436 ) — (436 ) 

Exercise of stock options, net of 

forfeitures 3,298 — — — — — — —

Stock based compensation — — 2,612 — — 2,612 — 2,612 

Comprehensive loss: 

Net loss — — — — (1,764 ) (1,764 ) — (1,764 ) 

Comprehensive loss — — — — — (1,764 ) — (1,764 ) 

Issuance of preferred stock of 

subsidiary — — — — — — 27,391 27,391 

Balance at December 31, 2011 64,706,750 $ 316,346 $ 25,376 $ — $ (133,919 ) $ 207,803 $ 27,391 $ 235,194 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF CASH FLOWS 

 

 Years Ended December 31, 

 2011 2010 2009 

 (in thousands) 

CASH FLOWS FROM OPERATING ACTIVITIES: 

Net income (loss) $ (740 ) $ (12,460 ) $ 48,846 

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

Depreciation, depletion and amortization 15,216 9,306 16,484 

Impairment of natural gas and oil properties — — 68,729 

Stock-based compensation 2,612 2,765 3,547 

Unrealized natural gas hedge (gain) loss (2,336 ) (11,214 ) 7,767 

Realized loss (gain) on derivative contracts (1,735 ) 1,437 (3,053 ) 

Amortization of deferred financing costs and debt discount 249 283 1,964 

Accretion of asset retirement obligation 534 396 379 

Loss on early extinguishment of debt — — 7,027 

Gain on sale of assets — — (211,162 ) 

Unrealized warrant derivative (gain) loss — (205 ) 205 

Dividend on preferred stock attributable to non-controlling interest (1,024 ) — —

Accrued litigation settlement liability — 3,150 —

Changes in operating assets and liabilities: 

Accounts receivable (6,672 ) 1,565 2,278 

Commodity derivative contracts (54 ) 1,232 2,893 

Prepaid expenses (100 ) (522 ) 151 

Accrued taxes payable — (1,420 ) 75,887 

Accounts payable and accrued liabilities 4,303 (385 ) (8,426 ) 

Net cash provided by (used in) operating activities 10,253 (6,072 ) 13,516 

CASH FLOWS FROM INVESTING ACTIVITIES: 

Development and purchase of natural gas and oil properties (73,718 ) (58,512 ) (49,230 ) 

Advances to operators (8,392 ) (300 ) (6,044 ) 

Acquisition of natural gas and oil properties — (28,887 ) —

Proceeds from sale of natural gas and oil properties — 49,197 251,267 

Proceeds from non-operators 18,740 98 (72 ) 

Purchase of furniture and equipment (454 ) (308 ) (42 ) 

Purchase of term deposit — (4,855 ) (69,662 ) 

Net cash (used in) provided by investing activities (63,824 ) (43,567 ) 126,217 

CASH FLOWS FROM FINANCING ACTIVITIES: 

Proceeds from issuance of common shares, net of issuance costs — 52,537 13,829 

Proceeds from short-term loan — — 17,000 

Proceeds from term loan — — 25,000 

Proceeds from revolving credit facility 71,000 42,000 —

Repayment of 12 3/4% senior secured notes — — (100,000 ) 

Repayment of term loan — — (25,000 ) 

Repayment of revolving credit facility (41,000 ) (42,000 ) (18,875 ) 

Repayment of convertible senior unsecured subordinated debentures — — (30,000 ) 

Repayment of subordinated unsecured notes — — (3,250 ) 

Repayment of short-term loan — (17,000 ) —

Proceeds from issuance of preferred stock, net of issuance costs 27,391 — —

Deferred financing charges (276 ) (27 ) (2,466 ) 

Other (336 ) (298 ) (258 ) 

Net cash provided by (used in) financing activities 56,779 35,212 (124,020 ) 
The accompanying notes are an integral part of these consolidated financial statements. 

F- 7 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 3,208 (14,427 ) 15,713 

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 7,439 21,866 6,153 

CASH AND CASH EQUIVALENTS, END OF PERIOD $ 10,647 $ 7,439 $ 21,866 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES 

CONSOLIDATED BALANCE SHEETS 

 December 31, 

 2011 2010 

 (in thousands) 

ASSETS 

CURRENT ASSETS: 

Cash and cash equivalents $ 10,595 $ 7,401 

Accounts receivable, net of allowance for doubtful accounts of $551 and $571, respectively 10,703 4,034 

Commodity derivative contracts 19,385 10,229 

Prepaid expenses 1,088 999 

Total current assets 41,771 22,663 

PROPERTY, PLANT AND EQUIPMENT: 

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

Unproved properties, excluded from amortization 78,302 162,230 

Proved properties 514,349 345,034 

Total natural gas and oil properties 592,651 507,264 

Furniture and equipment 1,629 1,175 

Total property, plant and equipment 594,280 508,439 

Accumulated depreciation, depletion and amortization (308,541 ) (293,325 ) 

Total property, plant and equipment, net 285,739 215,114 

OTHER ASSETS: 

Restricted cash 25 25 

Commodity derivative contracts 4,130 8,482 

Deferred charges, net 535 508 

Advances to operators and other 2,067 304 

Total other assets 6,757 9,319 

TOTAL ASSETS $ 334,267 $ 247,096 

LIABILITIES AND STOCKHOLDERS’ EQUITY 

CURRENT LIABILITIES: 

Accounts payable $ 17,682 $ 8,288 

Revenue payable 4,137 4,331 

Accrued interest 144 138 

Accrued drilling and operating costs 4,647 1,490 

Advances from non-operators 19,523 783 

Commodity derivative contracts 6,479 1,991 

Commodity derivative premium payable 4,725 3,451 

Accrued litigation settlement liability 800 3,164 

Other accrued liabilities 1,654 2,017 

Total current liabilities 59,791 25,653 

LONG-TERM LIABILITIES: 

Long-term debt 30,000 —

Commodity derivative contracts 1,163 1,521 

Commodity derivative premium payable — 4,725 

Accrued litigation settlement liability — 800 

Asset retirement obligation 8,268 7,243 

Due to parent 27,432 25,193 

Total long-term liabilities 66,863 39,482 

Commitments and contingencies (Note 15) 

STOCKHOLDERS’ EQUITY: 

Preferred stock, $0.01 par value; 10,000,000 shares authorized; 1,364,543 shares issued and outstanding at 

December 31, 2011 with liquidation preference of $25.00 per share 14 —
The accompanying notes are an integral part of these consolidated financial statements. 

F- 8 

Common stock, no par value; 1,000 shares authorized; 750 shares issued and outstanding 239,431 240,431 

Additional paid-in capital 27,377 —

Accumulated deficit (59,209 ) (58,470 ) 

Total stockholders’ equity 207,613 181,961 

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY $ 334,267 $ 247,096 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF OPERATIONS 

 

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

F- 9 

 Years Ended December 31, 

 2011 2010 2009 

 (in thousands) 

REVENUES: 

Natural gas $ 33,391 $ 30,811 $ 40,405 

Oil 3,416 742 229 

NGLs 1,092 — —

Total natural gas, oil and NGLs revenues 37,899 31,553 40,634 

Unrealized natural gas hedge gain (loss) 2,336 11,214 (7,767 ) 

Total revenues 40,235 42,767 32,867 

EXPENSES: 

Production taxes 620 370 439 

Lease operating expenses 8,629 6,676 6,568 

Transportation, treating and gathering 4,501 4,654 1,547 

Depreciation, depletion and amortization 15,216 9,306 16,484 

Impairment of natural gas and oil properties — — 68,729 

Accretion of asset retirement obligation 534 396 379 

General and administrative expense 10,434 13,468 14,368 

Litigation settlement expense — 21,744 —

Total expenses 39,934 56,614 108,514 

INCOME (LOSS) FROM OPERATIONS 301 (13,847 ) (75,647 ) 

OTHER INCOME (EXPENSE): 

Interest expense (112 ) (97 ) (731 ) 

Early extinguishment of debt — — (15,902 ) 

Investment income and other 95 1,238 1,074 

Gain on sale of assets — — 211,162 

Foreign transaction gain 1 354 3,768 

INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES 285 (12,352 ) 123,724 

Provision for income tax expense (benefit) — (804 ) 70,117 

NET INCOME (LOSS) 285 (11,548 ) 53,607 

Dividend on preferred stock 1,024 — —

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDER $ (739 ) 

 $ (11,548 )  $ 53,607 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY 

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

F- 10 

 Preferred Stock Common Stock Additional 

Paid-in 

Capital 

 

Accumulated 

Other 

Comprehensive 

Income (Loss) 

 

Accumulated 

Deficit 

 Total 

Stockholder's 

 Shares Amount Shares Amount Equity 

 (in thousands, except share data) 

Balance at December 31, 

2008 — $ — 750 $ 210,894 — $ 2,637 $ (100,529 ) $ 113,002 

Distribution to Parent — — — (4,000 ) — — — (4,000 ) 

Comprehensive income: 

Commodity 

derivatives reclassified 

to earnings and other — — — — — (2,637 ) — (2,637 ) 

Net income — — — — — — 53,607 53,607 

Comprehensive 

income — — — — — — — 50,970 

Balance at December 31, 

2009 — — 750 206,894 — — (46,922 ) 159,972 

Distribution to Parent — — — (19,000 ) — — — (19,000 ) 

Contribution from 

Parent — — — 52,537 — — — 52,537 

Comprehenisve loss: 

Net loss — — — — — — (11,548 ) (11,548 ) 

Comprehensive 

loss (11,548 ) 

Balance at December 31, 

2010 — — 750 240,431 — — (58,470 ) 181,961 

Distribution to Parent — — — (1,000 ) — — — (1,000 ) 

Contribution from 

Parent — — — — — — — —

Issuance of preferred 

stock 1,364,543 14 — — 27,377 — — 27,391 

Preferred stock 

dividends — — — — — — (1,024 ) (1,024 ) 

Comprehenisve income: 

Net income — — — — — — 285 285 

Comprehensive 

income 285 

Balance at December 31, 

2011 1,364,543 $ 14 750 $ 239,431 $ 27,377 $ — $ (59,209 ) $ 207,613 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION USA, INC. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF CASH FLOWS 

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

 Years Ended December 31, 

 2011 2010 2009 

 (in thousands) 

CASH FLOWS FROM OPERATING ACTIVITIES: 

Net income (loss) $ (739 ) $ (11,548 ) $ 53,607 

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

Depreciation, depletion and amortization 15,216 9,306 16,484 

Impairment of natural gas and oil properties — — 68,729 

Stock-based compensation 2,612 2,765 3,547 

Unrealized natural gas hedge (gain) loss (2,336 ) (11,214 ) 7,767 

Realized loss (gain) on derivative contracts (1,735 ) 1,437 (3,053 ) 

Amortization of deferred financing costs and debt discount 249 247 1,293 

Accretion of asset retirement obligation 534 396 379 

Loss on early extinguishment of debt — — 7,027 

Gain on sale of assets — — (211,162 ) 

Litigation settlement payable — 3,150 —

Changes in operating assets and liabilities: 

Accounts receivable (6,669 ) 1,562 2,279 

Commodity derivative contracts (54 ) 1,232 2,893 

Prepaid expenses (137 ) (552 ) 128 

Accrued taxes payable — (1,420 ) 75,887 

Accounts payable and accrued liabilities 4,236 (45 ) (8,309 ) 

Net cash provided by (used in) operating activities 11,177 (4,684 ) 17,496 

CASH FLOWS FROM INVESTING ACTIVITIES: 

Development and purchase of natural gas and oil properties (73,718 ) (58,512 ) (49,230 ) 

Advances to operators (8,392 ) (300 ) (6,044 ) 

Acquisition of natural gas and oil properties — (28,887 ) —

Proceeds from sale of natural gas and oil properties — 49,197 251,267 

Proceeds from non-operators 18,740 98 (72 ) 

Purchase of furniture and equipment (454 ) (308 ) (42 ) 

Purchase of term deposit — (4,855 ) (69,662 ) 

Net cash (used in) provided by investing activities (63,824 ) (43,567 ) 126,217 

CASH FLOWS FROM FINANCING ACTIVITIES: 

Proceeds from term loan — — 25,000 

Proceeds from revolving credit facility 71,000 — —

Repayment of 12 3/4% senior secured notes — — (100,000 ) 

Repayment of term loan — — (25,000 ) 

Repayment of revolving credit facility (41,000 ) — (18,875 ) 

Proceeds from issuance of preferred stock, net of issuance costs 27,391 — —

Deferred financing charges (276 ) (27 ) (2,217 ) 

Contribution from (distribution to) Parent, net (1,374 ) 33,822 (6,939 ) 

Other 100 49 12 

Net cash provided by (used in) financing activities 55,841 33,844 (128,019 ) 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 3,194 (14,407 ) 15,694 

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 7,401 21,808 6,114 

CASH AND CASH EQUIVALENTS, END OF PERIOD $ 10,595 $ 7,401 $ 21,808 
F- 11 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 

1. Description of Business 

Gastar Exploration Ltd. is an independent energy company engaged in the exploration, development and production of natural gas and oil in 

the United States (“U.S.”). Gastar Exploration Ltd.'s principal business activities include the identification, acquisition, and subsequent exploration 

and development of natural gas and oil properties with an emphasis on unconventional reserves, such as shale resource plays. Gastar Exploration 

Ltd. is currently pursuing the development of liquids-rich natural gas in the Marcellus Shale play in the Appalachia area of West Virginia and 

central and southwestern Pennsylvania. Gastar Exploration Ltd. also holds prospective acreage in the deep Bossier play in East Texas and conducts 

coal bed methane (“CBM”) development activities within the Powder River Basin of Wyoming and Montana. 

Gastar Exploration Ltd. is a holding company and substantially all of its operations are conducted through, and substantially all of its assets 

are held by, its primary operating subsidiary, Gastar Exploration USA, Inc. and its wholly-owned subsidiaries. Unless otherwise stated or the 

context requires otherwise, all references in these notes to “Gastar USA” refer collectively to Gastar Exploration USA, Inc. and its wholly-owned 

subsidiaries, all references to “Parent” refer solely to Gastar Exploration Ltd., and all references to “Gastar,” the “Company” and similar terms refer 

collectively to Gastar Exploration Ltd. and its wholly-owned subsidiaries, including Gastar Exploration USA, Inc. 

2. Summary of Significant Accounting Policies 

Basis of Presentation 

These financial statements are a combined presentation of the consolidated financial statements of the Company and Gastar USA. Separate 

information is provided for the Company and Gastar USA as required. Except as otherwise noted, there are no material differences between the 

consolidated information for the Company presented herein and the consolidated information of Gastar USA. 

The consolidated financial statements of the Company and Gastar USA are stated in 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 (“U.S. GAAP”). The 

preparation of these financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the 

reported amounts of assets, liabilities, revenues, expenses, related disclosure of contingent assets and liabilities, proved natural gas and oil reserves

and the related disclosures in the accompanying consolidated financial statements. 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 Note 19, “Supplemental Oil and Gas Disclosures.” 

Reclassifications 

Certain reclassifications of prior year balances have been made to conform to current year presentation; these reclassifications have no impact 

on net income (loss). 

Subsequent Events 

In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the 

date the financial statements were issued and has disclosed certain subsequent events in these consolidated financial statements, as appropriate. 

Principles of Consolidation 

The consolidated financial statements of the Company include the accounts of Parent and the consolidated accounts of all its subsidiaries. The 

wholly-owned subsidiaries included in these consolidated accounts are Gastar USA, Gastar Exploration Texas, Inc. (“Gastar Texas, Inc.”), Gastar 

Exploration Texas LP (“Gastar Texas”), Gastar Exploration Texas LLC (“Gastar Texas LLC”), Gastar Exploration New South Wales, Inc. (“Gastar 

New South Wales”), Gastar Exploration Victoria, Inc. (“Gastar Victoria”) and, prior to 2009, Gastar Power Pty Ltd. (“Gastar Power”). All 

significant intercompany accounts and transactions have been eliminated in consolidation. 

The consolidated financial statements of Gastar USA include the accounts of Gastar USA and the consolidated accounts of all its subsidiaries. 

The wholly-owned subsidiaries included in these consolidated accounts are Gastar Texas, Inc., Gastar Texas, Gastar Texas LLC, Gastar New South 

Wales, Gastar Victoria, and, prior to 2009, Gastar Power. All significant 

F- 12 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

intercompany accounts and transactions have been eliminated in consolidation. 

Cash and Cash Equivalents 

The Company's cash and cash equivalents, which includes short-term investments such as money market deposits with a maturity of three 

months or less when purchased, amounted to $10.6 million and $7.4 million as of December 31, 2011 and 2010 , 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 

Deferred financing costs include costs of debt financings undertaken by the Company, including commissions, legal fees and other direct 

costs of financing. Using the effective interest method, the deferred financing costs are amortized over the term of the related debt instrument to 

interest expense. 

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 and are 

amortized as reserves are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. With the sale of the 

Company’s Australian Assets (as defined under Note 3, “Property, Plant and Equipment – Sale of Petroleum Exploration Licenses 238, 433 and 434 

and Repayment of Debt”) in 2009, the U.S. is the Company’s only remaining cost center. Capitalized costs include land acquisition costs, 

geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to 

acquisition, exploration and development activities. 

Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production 

F- 13 

 

For the Years Ended 

December 31, 

 2011 2010 2009 

 (in thousands) 

Allowance for doubtful accounts, beginning of year $ 571 $ 609 $ 560 

Expense — — 49 

Reductions (20 ) (38 ) —

Allowance for doubtful accounts, end of year $ 551 

 $ 571  $ 609 

 As of December 31, 

 2011 2010 

 

Deferred charges $ 2,249 $ 1,974 

Accumulated amortization (1,714 ) (1,466 ) 

Deferred charges, net $ 535 

 $ 508 

Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

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 quarterly to ascertain whether an 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 of accounting, 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 the Company’s proved reserves using prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month price for 

natural gas and oil prices 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 expense. 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. 

The Company’s estimate of proved reserves is based on the quantities of natural gas and oil that engineering and geological analyses 

demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. 

Netherland, Sewell & Associates, Inc. (“NSAI”) and Wright & Company, Inc. (“Wright”) prepare a reserve and economic evaluation of all the 

Company’s properties on a well-by-well basis utilizing information provided by the Company and information available from state agencies that 

collect information reported to it by the operators of the Company’s properties. As discussed below, the estimate of the Company’s proved reserves 

as of December 31, 2011 and 2010 have been prepared and presented in accordance with current rules and accounting standards promulgated by the 

Securities and Exchange Commission (the “SEC”). These rules require SEC reporting companies to prepare their reserve estimates using revised 

reserve definitions and revised pricing based on a 12-month unweighted arithmetic average of the first-day-of-the-month price. The previous rules 

required that reserve estimates be calculated using year-end pricing. 

Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, 

adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates and 

the projected cash flows derived from these reserve estimates in accordance with SEC guidelines. NSAI and Wright adhere to the same guidelines 

when preparing the reserve report. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and 

quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the 

individuals preparing the estimates, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from 

the ultimate quantities of natural gas, oil and NGLs eventually recovered. 

The Company assesses unproved properties for impairment periodically and recognizes a loss where circumstances indicate impairment in 

value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current 

drilling plans, favorable or unfavorable activity on the properties being evaluated and/or adjacent properties and current market conditions. In the 

event that factors indicate an impairment in value, unproved properties leasehold costs are reclassified to proved properties and depleted. 

Capitalized Interest 

The Company capitalizes interest on assets not being amortized related to specific projects such as its drilling in progress and unproven 

natural gas and oil property expenditures. The methodology for capitalizing interest on general funds begins with a determination of the borrowings 

applicable to the 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 debt. The primary debt instrument included in the rate 

calculation of capitalized interest incurred for the year-ended December 31, 2011 was the Revolving Credit Facility (as defined under Note 5, 

“Long-Term Debt”). Currently, the Company only capitalizes interest on its Revolving Credit Facility. 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, not to exceed the total interest on the 

qualifying debt instruments. To qualify for interest capitalization, the Company must continue to make progress on the development of the assets. 

Capitalized interest costs were approximately $817,000, $633,000 and $10.8 million for 2011, 2010 and 2009, respectively. 

F- 14 
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Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

Furniture and Equipment 

Furniture and equipment are recorded at historical cost and are depreciated on a straight-line basis over their estimated useful lives, which 

range from three to seven years. 

Fair Value of Financial Instruments 

The fair value of financial instruments is determined at discrete points in time based on relevant market information. Such estimates involve 

uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, term deposit, accounts receivable, 

prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. Derivative 

instruments are also recorded on the balance sheet at fair value. 

Derivative Instruments and Hedging Activity 

The Company uses derivative instruments in the form of natural gas costless collars, index swaps, basis and fixed price swaps and put and call 

options to manage price risks resulting from fluctuations in commodity prices of natural gas and oil associated with future natural gas production. 

Derivative instruments are recorded on the balance sheet at fair value and changes in the fair value of derivatives are recorded each period in current 

earnings. 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. Gains and losses on 

derivatives are included in revenue in the period in which they occur. The resulting cash flows from derivatives are reported as cash flows from 

operating activities. See Note 9, “Derivative Instruments and Hedging Activity.” 

Prior to October 1, 2008, the Company designated and accounted for its derivative instruments as cash flow hedges. 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 was delivered and 

affected earnings. For all derivative instruments previously designated as cash flow hedges, the Company was required to assess the effectiveness of 

the hedging relationships at inception and on a quarterly basis. 

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 gain (loss) within the Company’s 

consolidated statements of operations. Any gains or losses previously deferred under cash flow hedge accounting remained in accumulated other 

comprehensive income until the previously hedged production affected earnings or was no longer probable of occurring. All amounts previously 

recorded in other comprehensive income in 2008 were recorded in natural gas and oil revenues during 2009 as the hedged production was 

delivered. For 2011, 2010 and 2009, realized gains or losses from derivative contracts are included in natural gas revenues in the Company’s 

consolidated statement of operations. 

Revenue Recognition 

The Company uses the sales method of accounting for the sale of its natural gas, oil, condensate and NGLs and records revenues from the sale 

of such products when delivery to the customer has occurred and title has transferred. This recording of revenues occurs when natural gas, oil, 

condensate or NGLs have been delivered to a pipeline or a tank lifting has occurred. Under the sales method, revenues are recorded based on the 

Company’s net revenue interest, as delivered. When actual natural gas sales volumes exceed our delivered share of sales volumes, an over-produced 

imbalance occurs. To the extent an over-produced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given 

property, the Company records a liability. The Company had no material gas imbalances at December 31, 2011 and 2010. 

The Company records its share of revenues based on production volumes and contracted sales prices. The sales price for natural gas, oil, 

condensate and NGLs are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on 

contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect 

actual charges based on third party documents once received by the Company. In addition, natural gas, oil, condensate and NGLs volumes sold are 

not significantly different from the Company’s share of production. 

F- 15 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

The Company calculates and pays royalties on natural gas, oil, condensate and NGLs in accordance with the particular contractual provisions 

of the lease. Royalty liabilities are recorded in conjunction with the cash receipts for natural gas, oil and NGLs revenues and are included in revenue 

payable on the Company’s consolidated balance sheet. 

Asset Retirement Obligation 

Asset retirement costs and liabilities associated with future site restoration and abandonment of tangible long-lived assets are initially 

measured at fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value 

is recognized in the financial statements as the present value of expected future cash expenditures for site restoration and abandonment. Subsequent 

to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the 

amortization of the asset retirement cost, through depreciation, depletion and amortization, are recognized in the results of operations. 

Foreign Currency Exchange 

The consolidated financial statements of the Company are presented in U.S. dollars. The functional currency for Parent and all consolidated 

subsidiaries is U.S. dollars. Transactions in currencies other than the functional currency are recorded using the appropriate exchange rate at the 

time of the transaction. 

The majority of the Company’s operations are conducted in U.S. dollars. Prior to July 2009, the Company conducted natural gas property 

development in Australia. The Australian Assets were sold in July 2009, prior to reaching commercial operations. As a result of the sale of the 

Australian Assets, the Company no longer has long lived assets outside of the U.S. Limited operations are conducted by Parent in Canada. 

The Australian and Canadian records are maintained in the local currency and re-measured to the functional currency as follows: monetary 

assets and liabilities are converted using the balance sheet period-end date exchange rate, while the non-monetary assets and liabilities are converted 

using the historical exchange rate. Expenses and income items are converted using the weighted average exchange rates for the reporting period. 

Foreign transaction gains and losses are reported on the consolidated statement of operations. 

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. Deferred tax assets are routinely evaluated 

to determine the likelihood of realization and the Company must estimate its expected future taxable income to complete this assessment. 

Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future 

events such as future operating conditions, particularly related to prevailing natural gas, oil and NGLs prices, and future financial conditions. The 

estimates or assumptions used in determining future taxable income are consistent with those used in internal budgets and forecasts. 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 allowance 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 

Basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding. Diluted earnings or 

loss per share is computed based upon the weighted average number of common shares outstanding plus the incremental effect of the assumed 

issuance of common shares for all potentially dilutive securities. Diluted per share amounts reflect the potential dilution that could occur if 

securities or other contracts to issue common shares are exercised or converted to common shares. The treasury stock method is used to determine 

the dilutive effect of stock options, unvested restricted shares and warrants. 

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, 

F- 16 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

which approximates the vesting period. Stock-based 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. 

The Company records stock-based compensation costs for stock options granted based on the grant-date fair value as calculated using the 

Black-Scholes-Merton option-pricing model. The Black-Scholes-Merton model requires various highly judgmental assumptions including 

volatility, forfeiture rates and expected option life. If any of the assumptions used in the Black-Scholes-Merton model change significantly, stockbased compensation expense for future grants may differ materially from that recorded in the current period. Stock-based compensation cost for 

restricted shares granted is estimated at the grant date based on the prior day’s closing stock price. 

Joint Venture Operations 

The majority of the Company’s natural gas and oil exploration activities are conducted jointly with others. These consolidated financial 

statements reflect only the Company’s proportionate interest in such activities. 

Industry Segment and Geographic Information 

The Company operates in one industry segment, which is the exploration, development and production of natural gas and oil. Historically, the 

Company’s operational activities have been conducted in the U.S. and Australia, with only the U.S. having revenue generating operating results. All 

Australian operations were sold on July 13, 2009. As a result, the Company’s current operational activities and the Company’s consolidated 

revenues are generated from markets exclusively in the U.S., and the Company has no long lived assets located outside the U.S. 

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 canceled upon repurchase. 

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 reported as restricted cash 

and is excluded from cash and cash equivalents in the consolidated balance sheets. 

Recent Accounting Developments 

The following recently issued accounting pronouncements have been adopted or may impact us in future periods: 

Comprehensive Income. In June 2011, the Financial Accounting Standards Board (“FASB”) issued an amendment to previously issued 

guidance regarding the reporting and presentation of other comprehensive income. The amendments require that all non-owner changes in 

stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In 

the two-statement approach, the first statement should present total net income and its components followed consecutively by a second statement 

that should present total other comprehensive income, the components of other comprehensive income and the total of comprehensive income. 

Regardless of whether an entity chooses to present comprehensive income in a single continuous statement or in two separate but consecutive 

statements, the entity is required to present on the face of the financial statements reclassification adjustments for items that are reclassified from 

other comprehensive income to net income in the statement(s) where the components of net income and the components of other comprehensive 

income are presented. The amendments do not change the items that must be reported in other comprehensive income or when an item of other 

comprehensive income must be reclassified to net income. This guidance is effective for fiscal years, and interim periods within those years, 

beginning after December 15, 2011 and should be applied retrospectively. Earlier application is permitted. The adoption of this guidance will not 

impact our operating results, financial position or cash flows upon adoption. 

Fair Value Measurement. In May 2011, the FASB issued an amendment to previously issued guidance regarding fair value measurement 

and disclosure requirements. The amendments explain how to measure fair value and do not require additional fair value measurements and are not 

intended to establish valuation standards or affect valuation practices outside of financial reporting. The amendments result in common fair value 

measurement and disclosure requirements in U.S. GAAP and 

F- 17 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

International Financial Reporting Standards. This guidance is effective prospectively for interim and annual periods beginning after December 15, 

2011. Early application is not permitted. The adoption of this guidance will not impact our operating results, financial position or cash flows upon 

adoption. 

Business Combinations. In December 2010, the FASB's Emerging Issues Task Force issued an amendment to previously issued guidance 

regarding the pro forma revenue and earnings disclosure requirements for business combinations. The amendments specify that if a public entity 

presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business 

combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The 

amendments also expand the supplemental pro forma disclosures under current guidance to include a description of the nature and amount of 

material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and 

earnings. This guidance is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first 

annual reporting period beginning on or after December 15, 2010. Earlier application is permitted. The adoption of this guidance did not impact our 

operating results, financial position or cash flows. 

3. 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 of 

Texas, Pennsylvania, West Virginia, Wyoming and Montana in the U.S. The Company’s Australian properties were sold in July 2009. The 

Company’s total property, plant and equipment consists of the following: 

 

The Company's unproved properties not being amortized consisted of the following for the periods indicated: 

For the year ended December 31, 2011, management’s evaluation of unproved properties resulted in an impairment of unproved properties. 

Due to a decline in natural gas prices and the planned reduction in drilling activity for 2012 in East Texas, the Company reclassified $63.8 million 

of unproved properties to proved properties at December 31, 2011. For the year ended December 31, 2010, management's evaluation of unproved 

properties did not result in an impairment. 

For the year ended December 31, 2011, management's ceiling test evaluation utilized a weighted average price of $4.88 per Mcfe and did not 

result in an impairment of proved properties. For the year ended December 31, 2010, management’s 

 December 31, 

 2011 2010 

 (in thousands) 

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

Unproved properties $ 78,302 $ 162,230 

Proved properties 514,357 345,042 

Total natural gas and oil properties 592,659 507,272 

Furniture and equipment 1,629 1,175 

Total property and equipment 594,288 508,447 

Impairment of proved natural gas and oil properties (187,152 ) (187,152 ) 

Accumulated depreciation, depletion and amortization (121,396 ) (106,180 ) 

Total accumulated depreciation, depletion and amortization (308,548 ) (293,332 ) 

Total property and equipment, net $ 285,740 

 $ 215,115 

 December 31, 

 2011 2010 

 (in thousands) 

Unproved properties, excluded from amortization: 

Drilling in progress costs $ 3,958 $ 17,603 

Acreage acquisition costs 68,217 126,388 

Capitalized interest 6,127 18,239 

Total unproved properties excluded from amortization $ 78,302 

 $ 162,230 
F- 18 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

ceiling test evaluation utilized a weighted average price of $3.59 per Mcfe and did not result in an impairment of proved properties. For the year 

ended December 31, 2009, management's ceiling test evaluation at March 31, 2009 utilized a weighted average price of $2.66 per Mcfe and resulted 

in an impairment of proved properties of $68.7 million. 

Atinum Joint Venture 

In September 2010, Gastar USA entered into a joint venture (the "Atinum Joint Venture") pursuant to a purchase and sale agreement with an 

affiliate of Atinum Partners Co., Ltd. ("Atinum"), a Korean investment firm. Pursuant to the agreement, at the closing of the transactions on 

November 1, 2010, Gastar USA assigned to Atinum an initial 21.43% interest in all of its existing Marcellus Shale assets in West Virginia and 

Pennsylvania, which consisted of approximately 37,600 gross (34,200 net) acres and a 50% working interest in 16 producing shallow conventional 

wells and one non-producing vertical Marcellus Shale well. Atinum paid Gastar USA approximately $30.0 million in cash at the closing and paid an 

additional $40.0 million of Gastar USA's share of drilling costs over time in the form of a "drilling carry." Upon completion of the funding of the 

drilling carry, Gastar USA made additional assignments to Atinum, as necessary, so Atinum now owns a 50% interest in the 34,200 net acres of 

Marcellus Shale rights initially owned by Gastar USA. The terms of the drilling carry required Atinum to fund its ultimate 50% share of drilling, 

completion and infrastructure costs along with 75% of Gastar USA’s ultimate 50% share of those same costs until the $40.0 million drilling carry 

had been satisfied. Atinum completed the funding of the drilling carry as of December 31, 2011. 

The Atinum Joint Venture is pursuing an initial three-year development program that calls for the partners to drill a minimum of 12 horizontal 

wells in 2011 and 20 and 24 operated horizontal wells in each of 2012 and 2013, respectively. As of December 31, 2011, 17 operated wells were 

drilled and cased under the Atinum Joint Venture. Through June 30, 2011, an initial AMI was established for potential additional acreage 

acquisitions in Ohio and New York along with the counties in West Virginia and Pennsylvania in which the initial Atinum Joint Venture interests 

were located. Within this initial AMI, Gastar USA will act as operator and is obligated to offer any future lease acquisitions within the AMI to 

Atinum on a 50/50 basis, and Atinum will pay Gastar USA on an annual basis an amount equal to 10% of lease bonuses and third party leasing 

costs up to $20.0 million and 5% of such costs on activities above $20.0 million. Subsequent to June 30, 2011, Atinum has the right to participate in 

any leasehold acquisitions made by Gastar USA outside of the initial AMI and within Ohio, New York, West Virginia or Pennsylvania, excluding 

the counties of Pendleton, Pocahontas, Preston, Randolph and Tucker, West Virginia, on terms identical to those governing the existing Atinum 

Joint Venture. 

Marcellus Shale Leasehold Acquisition 

In December 2010, Gastar USA completed a $28.9 million acquisition of undeveloped leasehold in the Marcellus Shale concentrated in 

Preston, Tucker, Pocahontas, Randolph and Pendleton Counties, West Virginia, including a gathering system comprised of 41 miles of four and six 

inch steel pipe, a salt water disposal well and five conventional producing wells. This acreage is not included in the Atinum Joint Venture and the 

counties in which the acquired assets are located are not part of the initial AMI. 

Sale of Petroleum Exploration Licenses 238, 433, and 434 and Repayment of Debt 

On July 13, 2009, Gastar New South Wales and Gastar USA completed the sale of all of the Company’s 35% working interest in Petroleum 

Exploration Licenses (“PEL”) 238 (including Petroleum Production License 3), PEL 433, and PEL 434 in New South Wales, Australia and the 

concurrent sale of the Company’s common shares of Gastar Power, the Company’s wholly-owned subsidiary holding its 35% working interest in 

the Wilga Park Power Station (collectively, the “Australian Assets”), to Santos QNT Pty Ltd. and Santos International Holdings Pty Ltd. 

(collectively, “Santos”) for an aggregate purchase price of $250.4 million (AU$320.0 million), before transaction costs of $1.5 million, resulting in 

a gain on the sale of assets of $211.2 million. The sale was made pursuant to a definitive sale agreement dated July 2, 2009 by and among Gastar 

New South Wales, Gastar USA and Santos. The sale agreement also acknowledged the Company’s retention of its right to future cash payments of 

up to $10.0 million pursuant to a pre-existing farm-in agreement in the event certain production thresholds are reached on PEL 238. 

The Company used the proceeds from the sale of the Australian Assets to (i) repay the $13.0 million outstanding on its secured original 

revolving credit facility, (ii) repay in full its $25.0 million term loan, (iii) repurchase all of its outstanding $100.0 million 12 3 / 4 % senior secured 

notes due December 31, 2012 at a price of 106.375% of par, plus accrued and unpaid interest, (iv) repay, at par, an initial $10.3 million of its 

convertible subordinated debentures and (v) repay the remaining $300,000 of subordinated unsecured notes payable (described in Note 5, “LongTerm Debt”). 

F- 19 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

Sale of East Texas Gas Gathering System 

On November 16, 2009, Gastar USA completed the sale of all of its interest in the Hilltop gas gathering system (the “Hilltop Gathering 

System”), located in Leon and Robertson Counties, Texas, pursuant to a purchase and sale agreement with Hilltop Resort GS, LLC (“Hilltop 

Resort”), dated as of November 16, 2009, whereby Gastar USA conveyed its 70% interest in the Hilltop Gathering System to Hilltop Resort for 

approximately $19.1 million, net of transaction costs and expenses. Gastar USA also entered into purchase and sale agreements dated November 16, 

2009 with two existing working interest owners in the Hilltop area of East Texas, whereby Gastar USA conveyed the remaining 30% of its interest 

in the Hilltop Gathering System for an aggregate $2.7 million, net of working interest owner costs owed to Gastar USA. At the time of the sale, the 

Hilltop Gathering System was comprised of 20 miles of natural gas pipeline connected to 19 company-operated wells, which produce from the 

middle and lower Bossier and Knowles formations in East Texas. 

On November 16, 2009, concurrent with Gastar USA’s sale of its Hilltop Gathering System, Gastar Texas entered into a gas gathering 

agreement (“Hilltop Gathering Agreement”) effective November 1, 2009, with Hilltop Resort for an initial term of 15 years. The Hilltop Gathering 

Agreement covers delivery of Gastar USA’s gross production of natural gas in the Hilltop area of East Texas to certain delivery points provided 

under the gas sales contract, as well as additional delivery points that, from time to time, may be added. Gastar USA is also obligated to connect 

new wells that it drills within the area covered by the Hilltop Gathering Agreement to the Hilltop Gathering System. The Hilltop Gathering 

Agreement provides for a minimum quarterly gathering gross production volume of 50.0 MMcf per day (35.0 MMcf per day net to Gastar USA) 

times the number of days in the quarter for five years from the effective date of November 1, 2009. If quarterly production is less than the minimum 

quarterly requirement, the gathering fee is payable on such deficit. If excess quarterly production exists, such excess is carried forward to be used to 

offset any future deficit quarters. The gathering fee on the initial gross 25 Bcf of production is $0.325 per Mcf, reducing in steps to $0.225 per Mcf 

when cumulative gross production reaches 300 Bcf. In October 2011, the cumulative gross production contractual volume of 25 Bcf was reached 

and the fee was reduced to $0.30 per Mcf. For the years ended December 31, 2011, 2010 and 2009, Gastar USA paid $ 1.5 million, $1.3 million and 

$78,000, respectively, to Hilltop Resort as a result of actual production volumes being less than minimum contractual volume requirements per the 

Hilltop Gathering Agreement. Gastar USA does not expect to meet the minimum quarterly requirements in the near future. 

4. Short-Term Loan 

On November 20, 2009, Parent entered into a $17.0 million secured short-term loan agreement with the lender parties and administrative 

agent thereto (the “Short-Term Loan”). Concurrent with the execution of the Short-Term Loan, Parent drew $17.0 million and used the proceeds, 

together with cash on hand, to repay all $19.7 million of its then outstanding 9.75% convertible senior unsecured subordinated debentures due 

November 20, 2009 (the “Convertible Subordinated Debentures”). 

The Short-Term Loan bore interest at the floating prime rate of the lender. The prime rate at December 31, 2009 was 5.0% per annum. 

Amounts outstanding under the Short-Term Loan were repayable prior to maturity, together with all accrued and unpaid interest relating to the 

amount prepaid, without prepayment penalty. The Short-Term Loan contained various covenants, including restrictions on liens, restrictions on 

incurring other indebtedness without the lenders’ consent, restrictions on dividends and other restricted payments and restrictions on entering into 

certain transactions. 

Amounts outstanding under the Short-Term Loan were secured by a second priority lien on all of the issued and outstanding shares of Gastar 

USA, pursuant to the Second Lien Security Agreement (Pledge) dated November 20, 2009 (“Second Lien”), by and between the Company and the 

administrative agent for the lenders under the Short-Term Loan. Additionally, amounts outstanding under the Short-Term Loan were secured by a 

security interest in all funds of the Company on deposit with the administrative agent and each lender that was a party to the Short-Term Loan. 

In order to provide for Parent’s borrowings under the Short-Term Loan and related repayments and the granting of the Second Lien, on 

November 20, 2009, Gastar USA, together with Parent and certain of its subsidiaries as the guarantors (“Subsidiary Guarantors”), and the lenders 

and administrative agent party thereto, entered into the Consent and First Amendment to Amended and Restated Credit Agreement (the “First 

Amendment”) amending the Revolving Credit Facility. See Note 5, “Long-Term Debt, Revolving Credit Facility.” 

The Short-Term Loan was repaid in full on January 8, 2010. 

F- 20 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

5. Long-Term Debt 

Amended and Restated Revolving Credit Facility 

On October 28, 2009, Gastar USA, together with Parent and Subsidiary Guarantors, and the lenders, administrative agent and letter of credit 

issuer party thereto, entered into an amended and restated credit facility, amending and restating in its entirety the original revolving credit facility

(the “Revolving Credit Facility”). The Revolving Credit Facility provided an initial borrowing base of $47.5 million, with borrowings bearing 

interest, at Gastar USA's election, at the prime rate or LIBO rate plus an applicable margin. Pursuant to the Revolving Credit Facility, the applicable 

interest rate margin varies from 1.0% to 2.0% in the case of borrowings based on the prime rate and from 2.5% to 3.5% in the case of borrowings 

based on LIBO rate, depending on the utilization percentage in relation to the borrowing base. An annual commitment fee of 0.50% is payable 

quarterly, based on the unutilized balance of the borrowing base. The Revolving Credit Facility had an original scheduled maturity date of 

January 2, 2013. 

In order to provide for the Company’s borrowings under the Short-Term Loan and related repayments and the granting of the Second Lien on 

November 20, 2009, Gastar USA, together with Parent and Subsidiary Guarantors and the lender parties and administrative agent thereto, entered 

into the First Amendment amending the Revolving Credit Facility. In addition to permitting the incurrence of debt under the Short-Term Loan, the 

First Amendment also amended the Revolving Credit Facility, by, among other things, reducing the borrowing base from $47.5 million to $30.5 

million until the Short-Term Loan was repaid in full, at which time the borrowing base would be automatically increased to $47.5 million until the 

next scheduled borrowing base redetermination. The borrowing base was increased to $47.5 million from $30.5 million subsequent to the 

repayment of the Short-Term Loan in January 2010. 

The Revolving Credit Facility is guaranteed by Parent and all of 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 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 Gastar USA. 

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

All outstanding amounts owed under the Revolving Credit Facility become due and payable upon the occurrence of certain usual and 

customary events of default, including among others: 

Should there occur a Change of Control of 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 immediately due, 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. 

F- 21 

• Restrictions on liens; 

• Restrictions on incurring other indebtedness without the lenders’ consent; 

• Restrictions on dividends and other restricted payments; 

• Maintenance of a minimum consolidated current ratio as of the end of each quarter of not less than 1.0 to 1.0, as adjusted; 

• Maintenance of a maximum ratio of indebtedness to EBITDA on a rolling four quarter basis, as adjusted, of not greater than 4.0 to 1.0; 

and 

• Maintenance of an interest coverage ratio on a rolling four quarter basis, as adjusted, of EBITDA to interest expense, as of the end of 

each quarter, to be less than 2.5 to 1.0. 

• 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 of Control (as defined in the Revolving Credit Facility) of the Parent. 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

Following the scheduled semi-annual borrowing base redetermination in May 2010, on June 24, 2010, Gastar USA, together with the other 

parties thereto, entered into the Second Amendment to the Amended and Restated Credit Agreement (the “Second Amendment”) amending that 

certain Amended and Restated Credit Agreement dated October 28, 2009 (as amended by the First Amendment, the Second Amendment, the Third 

Amendment (as defined below) and the Fourth Amendment (as defined below), the "Credit Agreement"). The Second Amendment amended the 

Revolving Credit Facility, by, among other things, allowing Gastar USA (i) to hedge up to 80% of the proved developed producing (“PDP”) 

reserves reflected in its reserve report using hedging other than floors and protective spreads, (ii) relatedly, to present to the administrative agent a

report showing any PDP additions resulting from new wells or the conversion of proved developed non-producing reserves to PDP reserves since 

the last reserve report in order to hedge the revised PDP reserves, and (iii) removing limitations on hedging using floors and protective spreads. 

Additionally, the Second Amendment reduced the borrowing base under the Revolving Credit Facility to $40.0 million from $47.5 million. On 

October 1, 2010, the borrowing base was increased to $47.5 million from the previous borrowing base of $40.0 million. 

On June 14, 2011, Gastar USA , together with the parties thereto, entered into the Third Amendment to the Amended and Restated Credit 

Agreement (the “Third Amendment”). The Third Amendment amended the Revolving Credit Facility, by, among other things, allowing Gastar 

USA to issue Series A Preferred Stock (as defined below) described in Note 10, “Capital Stock” and, as long as no default exists or would result 

from such payment and availability under the Revolving Credit Facility equals at least 10% of the then-existing borrowing base under the 

Revolving Credit Facility, pay cash dividends on the Series A Preferred Stock of no more than $10.0 million in the aggregate in each calendar year. 

On December 2, 2011, Gastar USA, together with the parties thereto, entered into the Fourth Amendment to Amended and Restated Credit 

Agreement, effective as of November 10, 2011 (the “Fourth Amendment”). The Fourth Amendment amended the Credit Agreement, by, among 

other things, (i) extending the maturity date on borrowings under the Revolving Credit Facility to September 30, 2015; (ii) allowing Gastar USA to 

hedge up to 100% of the PDP reserves reflected in its reserve report using hedging other than floors and protective spreads; and (iii) allowing no 

more than ten separate LIBO Rate Loans to be outstanding at one time. 

As of December 31, 2011, the Revolving Credit Facility had a borrowing base of $50.0 million, with $30.0 million of borrowings outstanding 

and availability of $20.0 million. Borrowing base redeterminations are scheduled semi-annually in May and November of each calendar year, with 

the next regularly scheduled redetermination set for November 2012. Gastar USA has requested that the May 2012 redetermination be accelerated 

to March 2012. Gastar USA and the lenders may request one additional unscheduled redetermination annually. On March 5, 2012, Gastar USA was 

notified by its lenders that, effective immediately, the borrowing base was increased from $50.0 million to $100.0 million resulting in current 

availability of $73.0 million as of March 6, 2012. 

At December 31, 2011, Gastar USA was not in compliance with the current ratio covenant under the Revolving Credit Facility. Gastar USA 

was granted a waiver in regards to the current ratio at December 31, 2011 and in conjunction with such waiver, Gastar USA was in compliance with 

all financial covenants under the Revolving Credit Facility at December 31, 2011. Gastar USA does not anticipate any issues with current ratio 

compliance in the future. 

Other Debt 

Credit support for the Company’s open derivatives at December 31, 2011 is provided through inter-creditor agreements or open accounts of 

up to $5.0 million. 

$25.0 Million Term Loan 

On February 17, 2009, Gastar USA drew $25.0 million under a $25.0 million term loan (the “$25.0 Million Term Loan”) to fund current and 

future capital commitments and operating costs. The $25.0 Million Term Loan bore interest at a fixed rate of 20% per annum and was to mature on 

February 15, 2012. The annual effective interest rate, after amortization of the fees paid to establish the $25.0 Million Term Loan was 21.9%. The 

$25.0 Million Term Loan contained 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 with the 

Company's original revolving credit facility. Amounts outstanding under the $25.0 Million Term Loan could be repaid 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 $25.0 Million Term Loan), all amounts outstanding under the $25.0 Million Term 

Loan were to be immediately due and payable. 

F- 22 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

Amounts outstanding under the $25.0 Million Term Loan were secured by a first priority lien on Gastar USA’s and certain of Parent’s 

subsidiaries’ primary natural gas and oil assets and certain other properties. The $25.0 Million Term Loan and other existing and future 

indebtedness incurred under the Company’s original revolving credit facility were senior to the liens securing the 12 3 / 4 % Senior Secured Notes. 

On July 13, 2009, the Company used approximately $27.5 million of the proceeds from the Australian Assets sale, described above, to repay 

in full, and thereby terminate, the $25.0 Million Term Loan. 

12 3 / 4 % Senior Secured Notes 

On November 29, 2007, Gastar USA sold $100.0 million aggregate principal amount of 12 3 / 4 % senior secured notes (the “12 3 / 4 % Senior 

Secured Notes”) at an issue price of 99.50% pursuant to an indenture, dated as of November 29, 2007 (the “Base Indenture”), by and among Parent, 

Gastar USA, Wells Fargo Bank, National Association, as trustee and Collateral Agent (the “Trustee”) and certain subsidiaries of Parent. The 12 3 / 4 

% Senior Secured Notes were fully and unconditionally guaranteed (the “Guarantees”) jointly and severally by Gastar USA, Parent, and all of 

Parent’s existing and future material domestic subsidiaries. The 12 3 / 4 % Senior Secured Notes and the Guarantees were secured by a second lien 

on Gastar USA’s principal domestic natural gas and oil properties and other assets that also secured the Company's original revolving credit facility, 

subject to certain exceptions. The 12 3 / 4 % Senior Secured Notes were to mature on December 1, 2012. On February 16, 2009, the parties to the 

Indenture entered into a supplemental indenture with the Trustee to amend and modify the Indenture (the “Supplemental Indenture” and together 

with the Base Indenture, the “Indenture”) to enable the Company to enter into the $25.0 Million Term Loan. 

On July 13, 2009, Gastar USA initiated an offer (the “Asset Sale Offer”) to purchase any and all of its outstanding 12 3 / 4 % Senior Secured 

Notes from the holders upon the terms and subject to the conditions set forth in the asset sale offer statement, dated July 13, 2009 (the “Asset Sale 

Offer Statement”). The Asset Sale Offer Statement was made in accordance with the terms of the Indenture. 

The purpose of the Asset Sale Offer was to comply with the provisions of the Indenture, whereby if the Company had major asset sale excess 

proceeds (as defined therein) following the receipt of net proceeds from a sale of assets, the Company was required to offer to purchase the 

maximum principal amount of 12 3 / 4 % Senior Secured Notes that could be purchased with such major asset sale excess proceeds. 

On August 6, 2009, the note-holders tendered to the Company the outstanding $100.0 million principal amount of the 12 3 / 4 % Senior 

Secured Notes at 106.375% of par, plus accrued and unpaid interest. On August 7, 2009, the Company used a portion of the net proceeds from the 

sale of the Australian Assets to retire in full the 12 3 / 4 % Senior Secured Notes and to discharge all of its obligations under the Indenture by 

directly tendering payment of $108.7 million, including accrued interest, to the note holders and ultimate cancellation of the 12 3 / 4 % Senior 

Secured Notes by the Trustee. 

Convertible Subordinated Debentures 

In November 2004, the Company issued $30.0 million of Convertible Subordinated Debentures. The Convertible Subordinated Debentures 

had a term of five years, were due November 20, 2009 and bore interest at 9.75% per annum, payable quarterly. As of September 30, 2009, a total 

of $10.3 million of Convertible Subordinated Debentures had been tendered, at par, to the Company for early retirement. Concurrent with the 

execution of the Short-Term Loan on November 20, 2009, the Company drew $17.0 million and used the proceeds, together with cash on hand, to 

repay all $19.7 million of outstanding Convertible Subordinated Debentures. 

Subordinated Unsecured Notes Payable 

The Company’s $3.25 million 10.0% subordinated unsecured notes payable (the “Subordinated Unsecured Notes Payable”) matured from 

April to September 2009. As of December 31, 2009, the Company had repaid all outstanding amounts under the Subordinated Unsecured Notes 

Payable. 

F- 23 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

6. Asset Retirement Obligation 

A summary of the activity related to the asset retirement obligation is as follows: 

 

7. Fair Value Measurements 

The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized nonfinancial assets and liabilities, such as asset retirement obligations, unproved properties and other property and equipment, at fair value on a nonrecurring basis. For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements 

to assess the inputs used to develop these measurements. The Company assesses its unproved properties for impairment whenever events or 

circumstances indicate the carrying value of those properties may not be recoverable. The fair value of the unproved properties is measured using 

an income approach based upon internal estimates of future production levels, current and future prices, drilling and operating costs, discount rates, 

current drilling plans and favorable and unfavorable drilling activity on the properties being evaluated and/or adjacent properties, which are Level 3 

inputs. During the year ended December 31, 2011, the Company recognized an impairment of unproved properties and reclassified from unproved 

to proved properties $63.8 million due to a decline in natural gas prices and the planned reduction in drilling activity for 2012 in East Texas. During 

the year ended December 31, 2010, the Company's evaluation of unproved properties did not result in an impairment. As no other fair value 

measurements are required to be recognized on a non-recurring basis at December 31, 2011, no additional disclosures are provided at December 31, 

2011. 

As defined in the guidance, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly 

transaction between market participants at the measurement date (an exit price). To estimate fair value, the Company utilizes market data or 

assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs 

to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The guidance establishes a fair 

value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted 

quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The 

three levels of the fair value hierarchy are as follows: 

F- 24 

 For the Years Ended December 31, 

 2011 2010 

 (in thousands) 

Asset retirement obligation, beginning of year $ 7,249 $ 5,943 

Liabilities incurred during period 492 1,023 

Accretion expense 534 396 

Revision in previous estimates and other — (113 ) 

Asset retirement obligation, end of year $ 8,275 

 $ 7,249 

• 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. These inputs may be used with internally developed methodologies or third 

party broker quotes that result in management’s best estimate of fair value. The Company’s valuation models consider various inputs 

including (i) quoted forward prices for commodities, (ii) time value, (iii) volatility factors and (iv) current market and contractual prices 

for the underlying instruments. Level 3 instruments are natural gas costless collars, index, basis and fixed price swaps, put and call 

options and warrants. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 

3 all of those whose fair value is based on significant unobservable inputs. 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value 

measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect 

the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values below

incorporates various factors, 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 Company has not elected to offset the fair value amounts 

recognized for multiple derivative instruments executed with the same counterparty, but report them gross on its consolidated balance sheets. 

The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at 

fair value on a recurring basis as of December 31, 2011 and 2010: 

 

 

The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended 

December 31, 2011 and 2010 . Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the 

assumptions a marketplace participant would have used at December 31, 2011 and 2010 . 

 

F- 25 

 Fair value as of December 31, 2011 

 Level 1 Level 2 Level 3 Total 

 (in thousands) 

Assets: 

Cash and cash equivalents $ 10,647 $ — $ — $ 10,647 

Restricted cash 50 — — 50 

Commodity derivative contracts — — 23,515 23,515 

Liabilities: 

Commodity derivative contracts — — (7,642 ) (7,642 ) 

Total $ 10,697 

 $ — $ 15,873  $ 26,570 

 Fair value as of December 31, 2010 

 Level 1 Level 2 Level 3 Total 

 (in thousands) 

Assets: 

Cash and cash equivalents $ 7,439 $ — $ — $ 7,439 

Restricted cash 50 — — 50 

Commodity derivative contracts — — 18,711 18,711 

Liabilities: 

Commodity derivative contracts — — (3,512 ) (3,512 ) 

Total $ 7,489 

 $ — $ 15,199  $ 22,688 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

_______________ 

At December 31, 2011 , the estimated fair value of accounts receivable, prepaid expenses, accounts and revenue payables and accrued 

liabilities approximates their carrying value due to their short-term nature. 

The fair value guidance, as amended, establishes that every derivative instrument is to be recorded on the balance sheet as either an asset or 

liability measured at fair value. See Note 9, “Derivative Instruments and Hedging Activity.” 

8. Equity Compensation Plans 

Share-Based Compensation Plan 

At the annual meeting of shareholders held June 4, 2009 (the “Annual Meeting”), Parent's shareholders approved amendments to Parent’s 

2006 Long-Term Stock Incentive Plan (the “2006 Plan”) that, effective as of April 1, 2009, merged the Parent’s Stock Option Plan (the “2002 Stock 

Option Plan”) with and into the 2006 Plan so that all outstanding equity awards and all future equity awards to be made to employees, officers and 

directors of the Company would be under the 2006 Plan. The merging of the 2002 Stock Option Plan with and into the 2006 Plan resulted in the 

cessation of the existence of the 2002 Stock Option Plan and the transfer of all common shares previously reserved and available for issuance under 

the 2002 Stock Option Plan, including any common shares subject to outstanding stock option awards previously granted under the 2002 Stock 

Option Plan prior to the effective date of the amendments, to the common shares reserved under the 2006 Plan. 

Additionally, the amendments to the 2006 Plan (i) provide that the Compensation Committee of the Parent, at its discretion, may provide, in 

an award agreement, that an individual who is granted an award under the 2006 Plan (a “participant”) may elect to have common shares withheld 

from or netted against the total number of common shares otherwise issuable to such participant pursuant to his award in order to pay the exercise 

or purchase price of such award and/or to satisfy all employer tax withholding obligations with respect to the participant’s award under the 2006 

Plan, (ii) clarify that common shares issuable under the 2006 Plan and forfeited back to the 2006 Plan will be deemed not to have been issued under 

the 2006 Plan and will again be available for the grant of an award under the 2006 Plan, (iii) provide that common shares withheld from or netted 

against an award granted under the 2006 Plan for payment of (a) the exercise or purchase price of an award and (b) all applicable employer tax 

withholding obligations associated with an award will be deemed not to have been issued under the 2006 Plan and will again be available for the 

grant of an award under the 2006 Plan, (iv) provide that the maximum number of common shares that may be subject to stock options, bonus stock 

awards and stock appreciation rights granted to any one individual during any calendar year may not exceed 200,000 common shares (subject to 

adjustment pursuant to Section 11(a) of the 2006 Plan) and (v) provide that the definition of “performance criteria” in the 2006 Plan include a 

criteria relating to the growth of proved natural gas and oil reserves of the Company. 

The 2006 Plan authorizes Parent’s Board of Directors (the "Parent Board") to issue stock options, stock appreciation rights, bonus stock 

awards and any other type of award, which are consistent with the 2006 Plan’s purposes to directors, officers 

F- 26 

 For the Years Ended December 31, 

 2011 2010 

 (in thousands) 

Balance at beginning of period $ 15,199 $ 7,638 

Total gains (realized or unrealized): 

included in earnings (1) 12,068 15,509 

included in other comprehensive income — —

Purchases — —

Issuances — —

Settlements (11,394 ) (7,948 ) 

Transfers in and (out) of Level 3 — —

Balance at end of period $ 15,873 $ 15,199 

The amount of total gains for the period included in earnings attributable to the change in unrealized gains or 

losses relating to assets still held at December 31, 2011 and 2010 $ 2,336  $ 11,419 

(1) Included in total revenues and other income (expense) on the statement of operations. 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

and employees of the Company and its subsidiaries covering a maximum of 6.0 million common shares. The contractual lives and vesting periods 

for grants are determined by the Parent Board at the time a grant is awarded. Recent stock option grants have an expiration of ten years. The vesting 

schedule for stock option grants has varied from two years to four years but generally has been over a four-year period vesting at 25% per year 

beginning on the first anniversary date of the grant. Stock options granted pursuant to the 2006 Plan have exercise prices determined by the Parent 

Board, but an exercise price cannot be less than the market price on the date immediately prior to the date of grant as reported by any stock 

exchange on which Parent’s common shares are listed. The vesting period for recent restricted common stock grants has been from two to four 

years, vesting annually from the date of grant in equal proportions. 

On August 3, 2009, Parent’s common shares began trading on a post 1-for-5 reverse split (the “1-for-5 Reverse Split”) basis. All common 

shares and per share information has been adjusted to reflect the 1-for-5 Reverse Split. See Note 10, “Capital Stock.” 

At December 31, 2011, 1,143,490 common shares of Parent were available for future stock-based compensation grants under the 2006 Plan. 

All common shares issued upon the exercise of stock option grants or vesting of restricted share grants are authorized, issued by Parent and are fully 

paid and non-assessable. 

 Determining Fair Value of Stock Options 

In determining the fair value of stock option grants, the Company utilized the following assumptions: 

Valuation and Amortization Method. The Company estimates the fair value of stock option awards using the Black-Scholes-Merton valuation 

model. The fair value of all awards is expensed using the “graded-vesting method.” 

Expected Life. The expected life of stock options granted represents the period of time that stock options are expected, on average, to be 

outstanding. The Company determined the expected life to be 6.25 years, based on historical information, for all stock options issued with four-year 

vesting periods and ten-year grant expirations. 

Expected Volatility. Using the Black-Scholes-Merton valuation model, the Company estimates the volatility of Parent's common shares at the 

beginning of the quarter in which the stock option is granted. The volatility is based on weighted average historical movements of Parent’s common 

share price on the NYSE Amex 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. Parent 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. 

Expected Forfeitures. Forfeitures of unvested stock options and restricted common shares are calculated at the beginning of the year as a 

percentage of all stock option and restricted common share grants. For 2011, 2010 and 2009, the Company used forfeiture rates in determining 

compensation expense of 8.5%, 9.8% and 6.5%, respectively. 

The fair value of each stock option grant is estimated on the date of grant using the Black-Scholes-Merton valuation pricing model. The table 

below summarizes the number of stock options granted and the fair value assumptions for the stock options granted for the period indicated: 

 

The weighted average grant date fair value of stock options granted and the intrinsic value of stock options exercised are 

F- 27 

 For the Years Ended December 31, 

 2011 2010 2009 

Stock options granted during the period — 80,000 266,300 

Expected life (in years) — 6.25 6.25 

Expected volatility — 68.1 % 59.3% - 60.2% 

Risk-free interest rate — 2.33% - 2.94% 1.97% - 2.81% 

Expected dividend rate —% 0.00 % 0.00 % 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

shown below for the periods indicated: 

 

_______________ 

 Stock Option Activity 

The following tables summarize certain information related to outstanding stock options under the 2006 Plan as of and for the year ended 

December 31, 2011 : 

 

 

Unrecognized expense as of December 31, 2011 for all outstanding options is $82,000 and will be recognized over a weighted average period 

of 1.64 years. 

F- 28 

 For the Years Ended December 31, 

 2011 2010 2009 

 (in thousands, except per share data) 

Weighted average grant date fair value per stock option granted $ — $ 2.66 $ 1.52 

Intrinsic value of stock options exercised (1) $ 18 $ 7 $ —

Grant date fair value of stock options vested $ 282 $ 739 $ 1,334 

(1) 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. 

 Shares 

Weighted Average 

Exercise Price 

per Share 

Weighted Average 

Remaining 

Contractual Term 

(in years) 

Aggregate 

Intrinsic Value 

(in thousands) 

Outstanding at December 31, 2010 1,107,100 $ 10.85 

Granted — — 

Exercised (15,000 ) 2.70 

Canceled/Expired — — 

Forfeited (108,200 ) 8.24 

Outstanding at December 31, 2011 983,900 $ 11.26 

Options vested and exercisable at December 31, 2011 837,750  $ 12.66  4.95  $ 51 

 Shares 

Weighted Average 

Fair Value 

per Share 

Weighted Average 

Exercise Price 

per Share 

Weighted Average 

Remaining 

Contractual Term 

(in years) 

Aggregate 

Intrinsic Value 

(in thousands) 

Outstanding non-vested options at 

December 31, 2010 289,275 $ 2.21 

Granted — — 

Vested (98,125 ) 2.87 

Forfeited (45,000 ) 1.57 

Outstanding non-vested options at 

December 31, 2011 146,150 

 $ 1.97  $ 3.25  7.64  $ 49 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

Restricted Share Activity 

The following table summarizes information related to restricted shares at December 31, 2011 : 

 

The following table summarizes the weighted average grant date fair value of restricted shares granted and the total fair value of shares vested 

for the periods indicated: 

 

Unrecognized compensation expense as of December 31, 2011 for all outstanding restricted share awards is $2.6 million and will be 

recognized over a weighted average period of 2.50 years. 

Stock-Based Compensation Expense 

For the years ended December 31, 2011 , 2010 and 2009 , the Company recorded stock-based compensation expense for stock options and 

restricted shares granted using the fair-value method of $2.6 million, $2.8 million and $3.5 million, respectively. All stock-based compensation 

costs were expensed and not tax affected, as the Company currently records no U.S. income tax expense. 

As of December 31, 2011 , the Company had approximately $2.7 million of total unrecognized compensation cost related to unvested stock 

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

 

 

9. Derivative Instruments and Hedging Activity 

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 costless collars, index, basis and fixed price swaps and 

put and call options to hedge natural gas price risk. 

Effective October 1, 2008, the Company elected to discontinue hedge accounting on all existing derivative contracts and 

 Shares 

Weighted Average 

Fair Value 

per Share 

Weighted Average 

Remaining 

Contractual Term 

(in years) 

Aggregate 

Intrinsic Value 

(in thousands) 

Non-vested restricted shares outstanding at December 31, 

2010 1,162,089 $ 5.38 

Granted 774,567 4.15 

Vested (391,627 ) 6.22 

Forfeited (143,698 ) 5.32 

Outstanding non-vested restricted shares at December 31, 

2011 1,401,331  $ 4.47  8.50  $ 4,456 

 For the Years Ended December 31, 

 2011 2010 2009 

 (in thousands, except per share data) 

Weighted average grant date fair value per restricted share $ 4.15 $ 4.84 $ 6.03 

Total fair value of restricted shares vested $ 2,436 $ 2,121 $ 1,480 

 Amount 

 (in thousands) 

2012 $ 1,631 

2013 749 

2014 258 

2015 36 

Total $ 2,674 
F- 29 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

elected not to designate any derivative contracts as cash flow hedges. Any hedge effectiveness related to the Company’s previous cash flow hedging 

relationships were to remain in other comprehensive income until the underlying forecasted transactions affected earnings. As a result, for the year 

ended December 31, 2009, the Company reported a gain of $2.6 million, which was reclassified into earnings as a result of previously discontinued 

cash flow hedges. As of December 31, 2009, all other comprehensive income had been reclassified to earnings. All 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 

gain (loss), while realized gains and losses related to contract settlements are recognized in natural gas and oil revenues. For the years ended 

December 31, 2011 and 2010, the Company reported unrealized gains of $2.3 million and $11.2 million, respectively. For the year ended 

December 31, 2009, the Company reported an unrealized loss of $7.8 million. 

As of December 31, 2011, the following derivative transactions were outstanding with the associated notational volumes and weighted 

average underlying hedge prices: 

_______________ 

As of December 31, 2011 , all of the Company’s economic derivative hedge positions were with a multinational energy company or large 

financial institutions, which are not known to the Company to be in default on their derivative positions. Credit support for the Company’s open 

derivatives at December 31, 2011 is provided under the Revolving Credit Facility through inter-creditor agreements or open credit accounts of up to 

$5.0 million. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed 

above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contains 

credit-risk related contingent features. 

In conjunction with certain derivative hedging activity, the Company deferred the payment of certain put premiums for the production month 

period July 2010 through December 2012. The put premium liabilities become payable monthly as the hedge production month becomes the prompt 

production month. The Company began amortizing the deferred put premium liabilities during July 2010. The following table provides information 

regarding the deferred put premium liabilities for the periods indicated: 

F- 30 

Settlement Period 

Derivative 

Instrument 

Average 

Daily 

Volume 

Total of 

Notional 

Volume 

Base 

Fixed 

Price 

Floor 

(Long) 

Short 

Put 

Ceiling 

(Short) 

 (in MMBtu’s) 

2012 Put spread 13,028 4,770,420 $ — $ 6.00 $ 4.05 $ —

2012 Costless three-way collar 7,410 2,711,580 — 5.73 4.00 6.88 

2012 (1) Call spread 2,000 550,000 — — — 4.50 

2012 Basis - HSC (2) 5,000 1,830,000 (0.08 ) — — —

2012 Basis - CIG (3) 500 183,000 (0.19 ) — — —

2013 Call spread 2,500 912,500 — — — 5.25 

2013 Costless three-way collar 2,500 912,500 — 5.00 4.00 6.45 

2013 Protective spread 2,500 912,500 5.44 — 3.79 —

2013 Fixed price swap 5,500 2,007,500 4.67 — — —

2013 Basis - HSC (2) 4,000 1,460,000 (0.11 ) — — —

2013 Basis - CIG (3) 650 237,250 (0.21 ) — — —

2014 Short calls 2,500 912,500 — — — 6.00 

(1) For the period April to December 2012 

(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) 

 

Warrants 

Parent reclassified the fair value of its warrants to purchase common stock, which had exercise price reset features, from equity to liability 

status as if these warrants were treated as a derivative liability since their date of issue in June 2008. On January 1, 2009, Parent reclassified from 

additional paid-in-capital, as a cumulative effect adjustment, $5.4 million to beginning retained earnings and did not recognize any value to 

common stock warrant liability for representing the fair value of such warrants on such date. The fair value of the warrants to purchase common 

stock was zero as of December 31, 2011 and 2010 , respectively, and Parent did not recognize any unrealized gains or losses in other income for the 

change in fair value of these warrants for the year ended December 31, 2011. Parent recognized $205,000 in unrealized gains in other income for 

the change in fair value of these warrants for the year ended December 31, 2010. The warrants expired on December 11, 2011. 

 Additional Disclosures about Derivative Instruments and Hedging Activities 

The tables below provide information on the location and amounts of derivative fair values in the consolidated statement of financial position 

and derivative gains and losses in the consolidated statement of operations for derivative instruments that are not designated as hedging instruments: 

 

F- 31 

 

December 31, 

2011 

December 31, 

2010 

 (in thousands) 

Current commodity derivative premium payable $ 4,725 $ 3,451 

Long-term commodity derivative premium payable — 4,725 

Total unamortized put premium liabilities $ 4,725 

 $ 8,176 

 

Fair Values of Derivative Instruments 

Derivative Assets (Liabilities) 

 Fair Value 

 Balance Sheet Location December 31, 2011 December 31, 2010 

 (in thousands) 

Derivatives not designated as hedging 

instruments 

Commodity derivative contracts Current assets $ 19,385 $ 10,229 

Commodity derivative contracts Other assets 4,130 8,482 

Commodity derivative contracts Current liabilities (6,479 ) (1,991 ) 

Commodity derivative contracts Long-term liabilities (1,163 ) (1,521 ) 

Total derivatives not designated as hedging 

instruments $ 15,873 

 $ 15,199 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

 

10. Capital Stock 

Common Shares 

The Parent’s articles of incorporation allow Parent to issue an unlimited number of common shares without par value. On July 23, 2009, 

Parent filed an article of amendment to its articles of incorporation with the Registrar of Corporations of Alberta, Canada for the purpose of 

affecting a 1-for-5 Reverse Split. The Parent’s shareholders approved the reverse split at the 2008 Annual General and Special Meeting of 

Shareholders held on June 20, 2008 by a special resolution authorizing a reverse split of the Company’s common shares on the basis of one (1) new 

common share for up to five (5) common shares outstanding or such fewer number of common shares as the Parent Board may, in its sole 

discretion, approve at a later date. The Parent Board approved the 1-for-5 Reverse Split on June 29, 2009. As of the opening of trading on August 3, 

2009, Parent’s common shares began trading on the NYSE Amex under the same symbol of “GST” on a post 1-for-5 Reverse Split basis. No scrip 

or fractional certificates were issued in connection with the 1-for-5 Reverse Split. Shareholders who otherwise would have been entitled to receive 

fractional shares because they held a number of common shares not evenly divisible by five received a number of shares after rounding up to the 

next common share. All Parent common share and per share amounts reported in the consolidated financial statements have been reported on a post 

1-for-5 Reverse Split basis. 

Effective July 6, 2009, Parent elected to voluntarily de-list its shares from trading on the Toronto Stock Exchange (“TSX”). The Parent 

decided to delist from the TSX because trading on two exchanges had become unduly costly and burdensome without providing any significant 

additional liquidity for Parent’s shareholders. 

Parent Preferred Shares 

On June 30, 2009, Parent filed an amendment to its articles of incorporation to be effective as of June 30, 2009 with the Registrar of 

Corporations of Alberta, Canada for the purpose of creating and adding an unlimited number of preferred shares to the authorized capital of Parent. 

Parent’s shareholders approved the amendment by special resolution at the 2007 Annual General and Special Meeting of Shareholders held on 

June 1, 2007. Pursuant to the amendment, the number of preferred shares which may be issued from time to time and the privileges, restrictions and 

conditions of such preferred shares when issued will be determined by the Parent Board. At December 31, 2011, there were no preferred shares 

issued or outstanding. 

Gastar USA Common Stock 

Prior to its conversion, as described below, Gastar USA’s articles of incorporation allowed Gastar USA to issue 1,000 shares of common 

stock, without par value. There were 750 shares issued and outstanding at December 31, 2011 and December 31, 2010, all of which were held by 

Parent. 

On May 24, 2011, Gastar USA converted from a Michigan corporation to a Delaware corporation (the “Conversion”). Following the 

Conversion, Gastar USA’s new Delaware certificate of incorporation allows Gastar USA to issue 1,000 shares of common stock, without par value. 

In connection with the Conversion, Parent’s 750 shares of common stock in the Michigan corporation were converted to 750 shares of common 

stock in the new Gastar USA Delaware corporation. 

F- 32 

 Amount of Gain (Loss) Recognized in Income on Derivatives 

 

Amount of Gain (Loss) Recognized in 

Income on Derivatives 

For the Year Ended 

 

Location of Gain (Loss) Recognized in 

Income on Derivatives 

December 31, 

2011 

December 31, 

2010 

December 31, 

2009 

 (in thousands) 

Derivatives not designated as 

hedging instruments 

Commodity derivative contracts Natural gas revenues $ 9,868 $ 4,137 $ 12,048 

Commodity derivative contracts Unrealized natural gas hedge gain (loss) 2,336 11,214 (7,767 ) 

Warrant derivative Unrealized warrant derivative gain (loss) — 205 (205 ) 

Total 

 $ 12,204  $ 15,556 $ 4,076 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

The stockholders’ equity presented in the balance sheet of Gastar USA as of December 31, 2010 gives effect to the Conversion as if it had 

occurred prior to December 31, 2010. 

Gastar USA Preferred Stock 

Prior to the Conversion, Gastar USA’s articles of incorporation did not authorize issuance of preferred stock. 

Following the Conversion, Gastar USA’s new Delaware certificate of incorporation allows Gastar USA to issue 10,000,000 shares of 

preferred stock, with $0.01 par value. The preferred stock may be issued from time to time in one or more series. Gastar USA’s Board of Directors 

(the “Gastar USA Board”) is authorized to fix the number of shares of any series of preferred stock and to determine the designation of any such 

series. The Gastar USA Board is also authorized to determine or alter the rights, preferences, privileges and restrictions granted to or imposed upon 

any wholly unissued series of preferred stock and, within the limits and restrictions stated in any resolution or resolutions of the Gastar USA Board 

originally fixing the number of shares constituting any series, to increase or decrease (but not below the number of shares of any such series 

outstanding) the number of shares of any series subsequent to the issues shares of that series). 

On June 23, 2011, Gastar USA sold an aggregate of 646,295 shares of its 8.625% Series A Cumulative Preferred Stock, par value $0.01 per 

share and liquidation preference $25.00 per share (the “Series A Preferred Stock”) through a best efforts underwritten public offering. The net 

proceeds to Gastar USA were approximately $13.6 million after deducting underwriting discounts, commissions and estimated offering expenses. 

On June 29, 2011, Gastar USA entered into an at-the-market sales agreement (“ATM Agreement”) with McNicoll, Lewis & Vlak LLC 

(“MLV”). According to the provisions of the ATM agreement, Gastar USA may offer and sell from time to time up to 3,400,000 additional shares 

of Series A Preferred Stock through MLV, as its sales agent. Sales of the units will be made by means of ordinary brokers’ transactions on the 

NYSE at market prices, in block transactions or as otherwise agreed between Gastar USA and MLV. 

As of December 31, 2011, Gastar USA had sold 718,248 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of 

$13.8 million, resulting in 1,364,543 total shares issued for net proceeds of $27.4 million at December 31, 2011. From January 1, 2012 to March 2, 

2012, Gastar USA sold an additional 1,472,142 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $28.0 million. 

The Series A Preferred Stock is subordinated to all of Gastar USA’s existing and future debt and all future capital stock designated as senior 

to the Series A Preferred Stock. Parent has entered into a guarantee agreement, whereby it will fully and unconditionally guarantee the payment of 

dividends that have been declared by the board of directors of Gastar USA, amounts payable upon redemption or liquidation, dissolution or winding 

up, and any other amounts due with respect to the Series A Preferred Stock, to the extent described in the guarantee agreement. Parent’s obligations 

with respect to the guarantee are effectively subordinated to all of its existing and future debt. 

The Series A Preferred Stock cannot be converted into common stock of Gastar USA or the Company, but may be redeemed by Gastar USA, 

at Gastar USA’s option, on or after June 23, 2014 for $25.00 per share plus any accrued and unpaid dividends or in certain circumstances prior to 

such date as a result of a change in control. Following a change in control, Gastar USA will have the option to redeem the Series A Preferred Stock, 

in whole but not in part, within 90 days after the date on which the change in control occurs, for cash at the following prices per share, plus accrued 

and unpaid dividends (whether or not declared), up to the redemption date: 

Gastar USA pays cumulative dividends on the Series A Preferred Stock at a fixed rate of 8.625% per annum of the $25.00 per share 

liquidation preference. For the year ended December 31, 2011, Gastar USA paid dividends of $1.0 million. 

Other Share Issuances 

On May 22, 2009, Parent sold 7,300,000 of its common shares in an underwritten public offering to investors in the U.S. 

F- 33 

Redemption Date 

Redemption 

Price 

Prior to June 23, 2012 $ 25.75 

On or after June 23, 2012 and prior to June 23, 2013 $ 25.50 

On or after June 23, 2013 and prior to June 23, 2014 $ 25.25 

On or after June 23, 2014 $ 25.00 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

pursuant to Parent’s Registration Statement on Form S-3, which was declared effective by the SEC on April 27, 2007, at a price of $2.00 per share, 

or $14.6 million before offering costs. 

On December 13, 2010, Parent sold 13,800,000 of its common shares in an underwritten public offering to investors in the U.S. pursuant to 

Parent’s Registration Statement on Form S-3, which was declared effective by the SEC on April 27, 2007, at a price of $4.00 per share, or $55.2 

million before offering costs. 

The following table provides information regarding the issuance and forfeitures of common shares pursuant to the 2006 Plan for the periods 

indicated: 

 

_______________ 

 Shares Reserved 

The following table summarizes the components of Parent's common shares reserved at December 31, 2011 : 

 

11. Interest and Debt Extinguishment Expense 

The following tables summarize the components of the Company's interest and debt extinguishment expense for the periods indicated: 

 

F- 34 

 For the Year Ended December 31, 

 2011 2010 

Other share issuances: 

Restricted common shares granted 774,567 440,550 

Restricted common shares vested 391,627 312,785 

Stock options exercised 15,000 3,000 

Common shares forfeited (1) 238,251 93,027 

(1) Represents common shares forfeited in connection with the payment of estimated withholding taxes on restricted common shares that vested 

during the period, common shares forfeited in connection with the payment of estimated withholding taxes and to settle the exercise price in 

cashless option exercises and/or common shares forfeited due to employee resignations. 

Common shares reserved for the: 

Exercise of stock options 983,900 

Total common shares reserved 983,900 

 For the Year Ended December 31, 

 2011 2010 2009 

 (in thousands) 

Interest expense: 

Cash and accrued $ 682 $ 500 $ 12,831 

Amortization of deferred financing costs and debt discount 248 283 1,964 

Capitalized interest (817 ) (633 ) (10,802 ) 

Total interest expense $ 113 $ 150 $ 3,993 

Early extinguishment of debt: 

Call premium $ — $ — $ 8,875 

Unamortized deferred financing costs and debt discount — — 7,027 

Total debt extinguishment expense $ — $ — $ 15,902 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

The following tables summarize the components of Gastar USA's interest and debt extinguishment expense for the periods indicated: 

 

12. Related Party Transactions 

Chesapeake Energy Corporation 

Chesapeake Energy Corporation (“Chesapeake”) acquired 6,781,768 of Parent's common shares during 2005 to 2007 in private placement 

transactions. Chesapeake has the right to have an observer present at meetings of the Parent Board. 

As of December 31, 2011 , Chesapeake owned 6,781,768 common shares, or 10.5%, of the Company’s outstanding common shares. 

13. Income Taxes 

The following table summarizes the components of the Company’s income (loss) before income taxes for the periods indicated: 

 

The Company’s income tax expense (benefit) consists of the following: 

 

F- 35 

 For the Year Ended December 31, 

 2011 2010 2009 

 (in thousands) 

Interest expense: 

Cash and accrued $ 681 $ 483 $ 10,240 

Amortization of deferred financing costs and debt discount 248 247 1,293 

Capitalized interest (817 ) (633 ) (10,802 ) 

Total interest expense $ 112 $ 97 $ 731 

Early extinguishment of debt: 

Call premium $ — $ — $ 8,875 

Unamortized deferred financing costs and debt discount — — 7,027 

Total debt extinguishment expense $ — $ — $ 15,902 

 For the Year Ended December 31, 

 2011 2010 2009 

 (in thousands) 

United States $ 285 $ (13,916 ) $ (90,174 ) 

Foreign (1,025 ) 652 209,337 

Total income (loss) before income taxes $ (740 )  $ (13,264 )  $ 119,163 

 For the Year Ended December 31, 

 2011 2010 2009 

 (in thousands) 

Current: 

Federal $ — $ — $ 200 

State — (12 ) 175 

Foreign — (792 ) 69,942 

Provision for income taxes $ — $ (804 )  $ 70,317 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

The following table provides a reconciliation of the Company’s effective tax rate from the U.S. 35% statutory rate for the periods indicated: 

 

The components of the Company’s U.S. deferred taxes are as follows: 

 

The Company utilized its U.S. net operating loss carry forwards in 2009 due to the U.S. gain recognition on the sale of the Australian Assets. 

The Company generated $64.5 million and $45.5 million of net operating loss for the years ending December 31, 2011 and 2010, respectively, 

which, if not utilized, will expire beginning in 2030. For U.S. federal income tax purposes, as of December 31, 2011 , the Company has foreign tax 

credit carry forwards of $50.7 million, which, if not utilized, will expire in 2019. The utilization of the net operating loss carry forward and the 

foreign tax credit carry forward are dependent on the Company generating future taxable income and U.S. tax liability, as well as other factors. 

Parent has the following approximate undeducted Canadian tax pools: 

 

F- 36 

 For the Year Ended December 31, 

 2011 2010 2009 

 (in thousands) 

Expected income tax provision (benefit) at statutory rate $ (259 ) $ (4,642 ) $ 41,707 

State tax, tax effected — (8 ) 114 

Non-deductible stock-based compensation expense 441 (4,311 ) 271 

Deferred tax effect of Canadian tax rate changes and other (103 ) (1,632 ) 1,849 

Deferred tax effect of Australian tax rate changes and other — — 722 

Non-deductible portion of U.S. net operating loss due to dual loss limitation — — 2,035 

U.S. tax on deemed dividend distribution to Parent — — 200 

Foreign tax credit adjustment — (1,366 ) —

Australian tax rate differences and adjustment — (1,337 ) —

Other 10 (95 ) (169 ) 

Other changes in valuation allowance (89 ) 12,587 23,588 

Actual income tax provision $ — $ (804 )  $ 70,317 

 As of December 31, 

 2011 2010 

 (in thousands) 

Deferred tax asset (liability): 

Capital assets $ (24,988 ) $ (222 ) 

Net operating loss carry forwards 40,360 16,115 

Foreign tax credit carry forwards 50,681 50,734 

Valuation allowance (66,053 ) (66,627 ) 

Net deferred tax asset $ — $ —

 As of December 31, 

 2011 2010 

 (in thousands) 

Canadian and foreign exploration and development expense $ 1,977 $ 1,955 

Undeducted share and senior secure note issuance costs $ 1,908 $ 2,786 

Undeducted non-capital and capital loss carry forwards $ 70,904 $ 68,333 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

For Canadian income tax purposes, Parent has net operating loss carry forwards, which if not utilized, began to expire in 2010 through 2030. 

The components of Parent’s Canadian deferred tax assets are as follows: 

 

Current authoritative guidance 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. At December 31, 2011 , the Company did not have any 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. and various state jurisdictions for the periods 2010 and forward 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. The Company was subjected to an audit by the Internal Revenue Service for the taxable period ended December 31, 2009. The audit 

began in April 2011 and was completed in January 2012 and did not result in any material adjustments or cash payments. 

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. 

14. Earnings or Loss per Share 

In accordance with the provisions of current authoritative guidance, 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 outstanding 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- 37 

 As of December 31, 

 2011 2010 

 (in thousands) 

Deferred tax asset: 

Capital assets $ 497 $ 489 

Share and senior secured note issuance costs 477 704 

Tax loss carry forwards 17,726 17,022 

Valuation allowance (18,700 ) (18,215 ) 

Net deferred tax asset $ — $ —
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

 

15. Commitments and Contingencies 

Contractual Obligations 

Gastar USA leases its office facilities and certain office equipment under non-cancelable operating lease agreements. For the years ended 

December 31, 2011 , 2010 and 2009 , office lease expense totaled approximately $160,000, $211,000 and $267,000, respectively. 

As of December 31, 2011 , the Company’s aggregate future minimum annual rental commitments under the non-cancelable leases for the next 

five years are as follows: 

 

Litigation 

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, Texas12th 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, which were sold to Chesapeake on November 4, 2005 (the “2005 Transaction”). 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 2005 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 

F- 38 

 For the Year Ended December 31, 

 2011 2010 2009 

 (in thousands, except per share and share data) 

Net income (loss) attributable to Gastar Exploration Ltd. $ (1,764 ) $ (12,460 ) $ 48,846 

Weighted average common shares outstanding – basic 63,003,579 49,813,617 46,102,662 

Incremental shares from outstanding stock options — — 2,783 

Incremental shares from unvested restricted shares — — 104,979 

Weighted average common shares outstanding – diluted 63,003,579 49,813,617 46,210,424 

Net income (loss) per common share attributable to Gastar Exploration Ltd. Common 

Shareholders: 

Basic $ (0.03 ) $ (0.25 ) $ 1.06 

Diluted $ (0.03 ) $ (0.25 ) $ 1.06 

Common shares excluded from denominator as anti-dilutive: 

Stock options 641,606 949,314 1,650,875 

Unvested restricted shares 810,235 100,078 436,034 

Warrants — 2,000,000 2,000,000 

Total 1,451,841  3,049,392  4,086,909 

2012 $ 537 

2013 534 

2014 541 

2015 460 

2016 309 

Thereafter —

 $ 2,381 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

claims for suit to quiet title, trespass to try title, tortuous interference with contract, conversion, money had and received, breach of contract and 

declaratory relief. The Company and Chesapeake filed a motion for rehearing on February 6, 2008, which was denied on March18, 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. On April 24, 

2009, the Texas Supreme Court denied the Petition for Review. 

Pursuant to a provision in the Purchase and Sale and Exploration Development Agreement, dated November 4, 2005 (the “Purchase and Sale 

Agreement”), between the Company and 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 Navasota’s exercise 

of its rights of specific performance 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, indicating that Chesapeake might assert such rescission and restitution as to the 

Purchase and Sale Agreement and the Common Share Purchase Agreement, both dated November 4, 2005. Chesapeake did not identify particular 

sums as to which it might 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 5.5 million common shares as part of the 2005 Transaction and/or other amounts. 

Chesapeake amended its answer to include cross-claims and counterclaims, including a claim for rescission. 

On or about June 9, 2009, Navasota filed and served its Fourth Amended Petition, essentially re-pleading its previously-asserted claims 

against the Company and Chesapeake. Navasota has exercised its rights of specific performance, and Chesapeake assigned leases to Navasota in 

July 2009. In March 2011, Chesapeake dismissed the cross-claims against the Company, including the claim for rescission, without prejudice to the 

subsequent refiling of those claims. On April 12, 2011, Navasota filed its Fifth Amended Petition. The Fifth Amended Petition adds a new claim 

that the Company allegedly has refused to offer Navasota interests in oil and gas leases located within an area of mutual interest, failed to assign 

Navasota overriding royalty interests, and failed to recognize back-in-after-payout interests. On September 2, 2011, Navasota filed its Sixth 

Amended Petition. The Sixth Amended Petition adds a new claim that the Company allegedly further violated Navasota’s preferential right under 

the July 7, 2000 operating agreement to the extent the Company sold any other interests in oil and gas leases located in an area of mutual interest 

without offering them to Navasota. The Sixth Amended Petition also added a claim that the Company violated the Texas Natural Resource Code 

sections 402 and 403 by failing to pay production proceeds to Navasota. 

The claims for monetary damages that Navasota asserts against the Company are as follows: 

1. A claim for recovery of the gross proceeds of production for the period that Chesapeake owned record title to the properties, in the 

approximate amount of $52.0 million. 

2. A claim for alleged lost hedging profits that Navasota claims that would have been realized if it had title to the properties during the period 

that Chesapeake owned record title to the properties, in the approximate amount of $32.0 million. 

The Company believes that these claims against the Company are invalid and that Navasota is not entitled to any recovery on its claims for 

monetary damages. In particular, the Company believes that by virtue of the costs incurred in connection with the properties during the time period 

that Chesapeake owned record title to the properties compared to amount reimbursed by Navasota to Chesapake to date, Navasota is in a better 

position economically than it would have been in had the assignments to Navasota been made in November 2005. The Company also believes that 

the claim that Navasota would have earned hedging profits if it had received the assignments in November 2005 is both legally invalid and factually 

wrong based on the undisputed evidence. 

The case is currently set for trial in Leon County, Texas on April 24, 2012. The Company intends to vigorously defend all claims asserted in 

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 87th Judicial District Court of 

Leon County, Texas. This lawsuit, filed on March 12, 2009, is a suit for trespass to try title and, in the alternative, to quiet title to an undivided 

mineral interest under several Company oil and gas leases covering approximately 4,273.7 gross acres (the “Leases”). The Company 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. The Company also contends that the defendants’ continued production of oil from wells located 

on the land in question is a trespass to real property for which the Company is entitled to receive damages. The defendants answered the 

F- 39 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

lawsuit and asserted certain affirmative defenses. The parties exchanged written discovery requests and responses. The parties exchanged 

documents responsive to requests for production. The defendants filed a counterclaim. The defendants claim that their leases are still valid and that 

they own a working interest and/or an overriding royalty in the Company’s Belin Nos. 1, 2 and 3 wells located in Leon County. The Company and 

the defendants attended mediation but no settlement was reached. On June 30, 2011, five individuals intervened in the lawsuit and claimed that they 

are owed overriding royalties under the same leases claimed by the defendants. The Company contends that the intervenors are not entitled to any 

overriding royalties because the leases claimed by the defendants and the intervenors have expired. The defendants, the intervenors and several 

third-party witnesses were deposed. On February 24, 2012, the Company and the intervenors reached a confidential settlement. The case was set for 

trial on March 5, 2012. On March 5, 2012, at the courthouse, the Company and the defendants agreed in principle to confidential settlement terms. 

The settlement documents have not been executed as of the date of this filing. The settlement, once executed, will have an effective date of April 1, 

2012. The Company does not expect the settlement to materially impact its operating results, financial position or cash flows. 

ClassicStar Mare Lease Litigation Settlement. In November 2010, the Company entered into a final settlement agreement and comprehensive 

general release with respect to the seven In re ClassicStar Mare Lease Litigation matters that we were involved in (collectively, the “ClassicStar 

Mare Lease Litigation”). Pursuant to such settlement agreement, the Company is required to pay to the plaintiffs an aggregate of $21.2 million in 

cash, including an initial $18.0 million payment paid late in December 2010 and the remaining $3.2 million as a non-interest bearing payment 

obligation consisting of sixteen consecutive monthly payments, the first of which was in the amount of $150,000 and was paid in January 2011 and 

the next fifteen of which shall be $200,000 each, in exchange for dismissal of the plaintiffs' claims in all seven cases. As of December 31, 2011, the 

Company has paid $20.4 million of the total settlement to the plaintiffs. 

The Company has been expensing legal defense costs on these proceedings as they are incurred. With respect to the Navasota Resources 

matter, the Company has not accrued a liability for settlement or other resolution of these proceedings because, in the Company’s judgment, the 

incurrence or amount of such liabilities is either not probable or not reasonably estimable. 

The Company is party to various legal proceedings arising in the normal course of business. The ultimate outcome of each of these matters 

cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a 

negative outcome may be in excess of amounts currently accrued for with respect to such matters. Net of available insurance and performance of 

contractual defense and indemnity obligations, where applicable, management does not believe any such matters will have a material adverse effect 

on the Company’s financial position, results of operations or cash flows. 

For the year ended December 31, 2010, the Company recorded $21.7 million in litigation settlement expense in the consolidated statement of 

operations, the majority of which related to the ClassicStar Mare Lease Litigation settlements and short-term and long-term accrued litigation 

settlement liabilities of $3.2 million and $800,000, respectively, on the consolidated balance sheet at December 31, 2010. 

Commitments 

In March 2008, Gastar USA entered into formal agreements with ETC Texas Pipeline, Ltd. (“ETC”) for the gathering, treating, purchase and 

transportation of Gastar USA's natural gas production from the Hilltop area of East Texas (the “ETC Contract”). The ETC Contract was effective 

September 1, 2007 and has a term of 10 years. ETC currently provides Gastar USA 50.0 MMcf per day of treating capacity and 150.0 MMcf per 

day of transportation capacity of production from Gastar USA’s wells, located in Leon and Robertson Counties, Texas. 

On November 16, 2009, concurrent with Gastar USA’s sale of its Hilltop Gathering System, Gastar Texas entered into the Hilltop Gathering 

Agreement effective November 1, 2009, with Hilltop Resort for an initial term of 15 years. The Hilltop Gathering Agreement covers delivery of 

Gastar USA’s gross production of natural gas in the Hilltop area of East Texas to certain delivery points provided under the ETC Contract, as well 

as additional delivery points that, from time to time, may be added. Gastar USA is also obligated to connect new wells that it drills within the area 

covered by the Hilltop Gathering Agreement to the Hilltop Gathering System. The Hilltop Gathering Agreement provides for a minimum quarterly 

gathering gross production volume of 50.0 MMcf per day (35.0 MMcf per day net to Gastar USA) times the number of days in the quarter for five 

years from the effective date of November 1, 2009. If quarterly production is less than the minimum quarterly requirement, the gathering fee is 

payable on such deficit. If excess quarterly production exists, such excess is carried forward to be used to offset any future deficit quarters. The 

gathering fee on the initial gross 25 Bcf of production is $0.325 per Mcf, reducing in steps to $0.225 per Mcf when cumulative gross production 

reaches 300 Bcf. For the year ended December 31, 2011 , 

F- 40 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

Gastar USA paid $ 1.5 million to Hilltop Resort as a result of actual production volumes being less than minimum contractual volume requirements. 

There is no assurance that Gastar USA will meet its minimum quarterly requirements in the future. 

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 present value of expected future cash 

flows. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) 

and the amortization of the asset retirement 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. At December 31, 2011 , the Company had total liabilities of $8.3 million related to asset retirement obligations recorded as longterm liabilities. Due to the nature of these obligations, the Company cannot determine precisely when the payments will be made to settle these 

obligations. See Note 6, “Asset Retirement Obligation.” 

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 predetermined 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 Chief Executive Officer and its Chief Financial Officer, effective February 24, 

2005 (as amended July 25, 2008 and February 3, 2011) and May 17, 2005 (as amended July 25, 2008), respectively. The agreements set forth, 

among other things, annual compensation, and adjustments thereto, bonus payments, fringe benefits, termination and severance provisions. The 

agreements renew annually; however, they may be terminated at any time with or without cause. 

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

Company, to indemnify them to 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 the beneficiary of such indemnification agreements. 

16. Concentration of Risk and Significant Customers

Approximately 79%, 88% and 85% of the Company’s natural gas, oil and NGLs revenues excluding realized hedge impact were derived from 

production from producing wells in the Hilltop area of East Texas for the years ended December 31, 2011 , 2010 and 2009 , respectively. 

Approximately 15%, 2% and 2% of the Company's natural gas, oil and NGLs revenues excluding realized hedge impact were derived from 

producing wells in Appalachia for the years ended December 31, 2011, 2010 and 2009, respectively. 

The following table provides information regarding our significant customers and the percentages of natural gas, oil and NGLs revenues, 

excluding realized hedge impact, which they represented for the periods indicated: 

F- 41 

 For the Years Ended December 31, 

 2011 2010 2009 

ETC 69 % 86 % 85 % 

Enserco Energy, Inc. 6 % 9 % 13 % 

Plains Marketing LP 10 % 2 % —% 

SEI 8 % —% —% 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

 

ETC treats, transports and purchases substantially all of the Company’s East Texas natural gas production, Plains purchases substantially all 

of the Company's East Texas oil production, Enserco purchases the Company’s Powder River Basin natural gas production, and SEI purchases the 

majority of the Company's Appalachia production. There are limited natural gas purchase and transportation alternatives currently available in the 

Hilltop area of East Texas and in Appalachia. If ETC, Enserco, Plains or SEI were to cease purchasing and transporting the Company’s natural gas 

and the Company was unable to obtain timely access to existing or future facilities on acceptable terms, or in the event of any significant change 

affecting these facilities, including delays in the commencement of operations of any new pipelines or the unavailability of the new pipelines or 

other facilities due to market conditions, mechanical reasons or otherwise, the Company’s ability to conduct normal operations would be restricted. 

However, the Company believes that the loss of ETC, Enserco, Plains or SEI would not have a long-term material adverse impact on the 

Company’s financial position or results of operations, as there are other purchasers operating in the areas. 

17. Statement of Cash Flows – Supplemental Information 

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

financial statements: 

 

The following is a summary of Gastar USA's supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated 

financial statements: 

F- 42 

 For the Year Ended December 31, 

 2011 2010 2009 

 (in thousands) 

Cash paid for interest $ 676 $ 497 $ 14,202 

Cash paid for taxes — 616 —

Cash paid for debt extinguishment — — 8,875 

Non-cash transactions: 

Term deposit surrendered for accrued taxes $ — $ 70,446 $ —

Capital expenditures excluded from accounts payable and accrued costs 4,600 2,725 (5,125 ) 

Capital expenditures excluded from prepaid expenses 48 — —

Asset retirement obligation included in natural gas and oil properties 492 910 516 

Application of advances to operators 6,529 246 10,247 

 For the Year Ended December 31, 

 2011 2010 2009 

 (in thousands) 

Cash paid for interest $ 675 $ 386 $ 11,308 

Cash paid for taxes — 414 —

Cash paid for debt extinguishment — — 8,875 

Non-cash transactions: 

Term deposit surrendered for accrued taxes $ — $ 70,446 $ —

Capital expenditures excluded from accounts payable and accrued costs 4,600 2,725 (5,125 ) 

Capital expenditures excluded from prepaid expenses 48 — —

Asset retirement obligation included in natural gas and oil properties 492 910 516 

Application of advances to operators 6,529 246 10,247 

Due to Parent - transfer to equity, net 2,612 (30,773 ) 7,546 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

18. Quarterly Consolidated Financial Data – Unaudited 

The following tables summarize the Company’s results of operations by quarter for the years ended December 31, 2011 and 2010 : 

 

_______________ 

_______________ 

F- 43 

 2011 

 

First 

Quarter 

Second 

Quarter 

Third 

Quarter 

Fourth 

Quarter 

 (in thousands, except share and per share data) 

Revenues $ 8,129 $ 9,016 $ 12,012 $ 11,078 

Income (loss) from operations (1) (1,907 ) 184 1,432 (340 ) 

Income (loss) before provision for income taxes (1,935 ) 157 1,402 (364 ) 

Net income (loss) (1,935 ) 157 1,402 (364 ) 

Dividend on preferred stock attributable to non-controlling interest — 31 388 605 

Net income (loss) attributable to Gastar Exploration Ltd. (1,935 ) 126 1,014 (969 ) 

Net income (loss) per common share attributable to Gastar Exploration Ltd. 

Common Shareholders: 

Basic $ (0.03 ) $ 0.00 $ 0.02 $ (0.02 ) 

Diluted $ (0.03 ) $ 0.00 $ 0.02 $ (0.02 ) 

Weighted average common shares outstanding: 

Basic 63,024,481 63,134,109 63,238,069 63,305,419 

Diluted 63,024,481 63,723,093 63,842,098 63,305,419 

(1) Loss from operations for the three months ended December 31, 2011 includes an additional $1.1 million of DD&A expense as a result of the 

reclassification of $63.8 million of unproved properties to proved properties at December 31, 2011 due to a decline in natural gas prices and the 

planned reduction in drilling activity for 2012 in East Texas. 

 2010 

 

First 

Quarter 

Second 

Quarter 

Third 

Quarter 

Fourth 

Quarter 

 (in thousands, except share and per share data) 

Revenues $ 16,136 $ 5,765 $ 14,144 $ 6,723 

Income (loss) from operations (1) 7,363 (3,040 ) (16,420 ) (2,922 ) 

Income (loss) before provision for income taxes 8,544 (2,441 ) (16,423 ) (2,944 ) 

Net income (loss) 9,393 (2,498 ) (16,411 ) (2,944 ) 

Net income (loss) per common share: 

Basic $ 0.19 $ (0.05 ) $ (0.33 ) $ (0.06 ) 

Diluted $ 0.19 $ (0.05 ) $ (0.33 ) $ (0.06 ) 

Weighted average common shares outstanding: 

Basic 48,997,016 49,042,874 49,148,207 52,066,371 

Diluted 49,486,656 49,042,874 49,148,207 52,066,371 

(1) Loss from operations for the three months ended September 30, 2010 and December 31, 2010 include litigation settlement expense of $21.2 

million and $594,000 , respectively. 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

The following tables summarize Gastar USA’s results of operations by quarter for the years ended December 31, 2011 and 2010 : 

_______________ 

_______________ 

19. Supplemental Oil and Gas Disclosures – Unaudited 

Capitalized Costs Relating Oil and Producing Activities 

The following table presents the Company’s aggregate capitalized costs relating to natural gas and oil producing activities for the periods 

indicated: 

 

F- 44 

 2011 

 

First 

Quarter 

Second 

Quarter 

Third 

Quarter 

Fourth 

Quarter 

 (in thousands, except share and per share data) 

Revenues $ 8,129 $ 9,016 $ 12,012 $ 11,078 

Income (loss) from operations (1) (1,726 ) 367 1,653 7 

Income (loss) before provision for income taxes (1,662 ) 341 1,623 (17 ) 

Net income (loss) (1,662 ) 341 1,623 (17 ) 

Dividend on preferred stock — 31 388 605 

Net income (loss) attributable to common stockholder (1,662 ) 310 1,235 (622 ) 

(1) Loss from operations for the three months ended December 31, 2011 includes an additional $1.1 million of DD&A expense as a result of the 

reclassification of $63.8 million of unproved properties to proved properties at December 31, 2011 due to a decline in natural gas prices and the 

planned reduction in drilling activity for 2012 in East Texas. 

 2010 

 

First 

Quarter 

Second 

Quarter 

Third 

Quarter 

Fourth 

Quarter 

 (in thousands, except share and per share data) 

Revenues $ 16,136 $ 5,765 $ 14,144 $ 6,722 

Income (loss) from operations (1) 7,880 (2,753 ) (16,223 ) (2,751 ) 

Income (loss) before provision for income taxes 8,965 (2,209 ) (16,235 ) (2,873 ) 

Net income (loss) 9,814 (2,266 ) (16,223 ) (2,873 ) 

(1) Loss from operations for the three months ended September 30, 2010 and December 31, 2010 include litigation settlement expense of $21.2 

million and $594,000 , respectively. 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

Pursuant to authoritative guidance for accounting for asset retirement obligations, net capitalized costs include related asset retirement costs 

of approximately $5.8 million, $5.4 million and $4.4 million at December 31, 2011 , 2010 and 2009 , respectively. 

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, 2011 , 

2010 and 2009 : 

 

F- 45 

 As of December 31, 

 2011 2010 2009 

 (in thousands) 

Proved properties: 

United States $ 514,357 $ 345,042 $ 313,100 

Total proved properties 514,357 345,042 313,100 

Unproved properties: 

United States 78,302 162,230 132,720 

Total unproved properties 78,302 162,230 132,720 

Total natural gas and oil properties 592,659 507,272 445,820 

Less: 

Impairment of proved natural gas and oil properties 

United States (187,152 ) (187,152 ) (187,152 ) 

Accumulated depreciation, depletion and amortization (120,436 ) (105,447 ) (96,315 ) 

Net capitalized costs $ 285,071  $ 214,673  $ 162,353 

 United States Australia Total 

 (in thousands) 

For the year ended December 31, 2011: 

Unproved property acquisition $ 19,552 $ — $ 19,552 

Exploration 47,668 — 47,668 

Development 18,167 — 18,167 

Total costs incurred $ 85,387 $ — $ 85,387 

For the year ended December 31, 2010: 

Unproved property acquisition $ 54,799 $ — $ 54,799 

Unproved property divestment (25,289 ) — (25,289 ) 

Proved property divestment (4,872 ) — (4,872 ) 

Exploration 12,648 — 12,648 

Development 24,166 — 24,166 

Total costs incurred $ 61,452 $ — $ 61,452 

For the year ended December 31, 2009: 

Unproved property acquisition $ 13,997 $ 14,457 $ 28,454 

Unproved property divestment — (37,594 ) (37,594 ) 

Proved property divestment (21,783 ) (604 ) (22,387 ) 

Exploration 12,731 — 12,731 

Development 13,653 — 13,653 

Total costs incurred $ 18,598  $ (23,741 )  $ (5,143 ) 
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 the Company’s results of operations for oil and gas producing activities for the periods indicated: 

 

The results of producing activities exclude interest charges and general corporate expenses and represent U.S. activities only due to no 

producing operations activities in Australia during 2011, 2010 and 2009. 

In accordance with current authoritative guidance, estimates of the Company’s proved reserves and future net revenues are made using 

benchmark prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month prices for natural gas and oil and were used in 

the Company’s reserve valuation as of December 31, 2011 and 2010. The following table provides the key natural gas and oil prices used as of the 

periods indicated to calculate reserves: 

 

These prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve report but are adjusted by 

lease in accordance with sales contracts and for energy content, quality, transportation, compression and gathering fees and regional price 

differentials. Estimated quantities of proved reserves and future net revenues are affected by natural gas prices and oil prices, which have fluctuated 

significantly in recent years. 

Net Proved and Proved Developed Reserve Summary 

Reserve Estimation. The reserve information presented below is based on estimates of net proved reserves as of December 31, 2011, 2010, 

and 2009 that were prepared by NSAI for the Hilltop Area of East Texas and the Powder River Basin of Wyoming and Montana and for Appalachia 

as of December 31, 2010 and 2009. Reserve information for Appalachia as of December 31, 2011 is based on estimates of net proved reserves 

prepared by Wright. A copy of NSAI and Wright’s summary reserve reports are included as Exhibit 99.1 and 99.2, respectively, to this Form 10-K. 

Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with 

reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods 

and governmental regulations (i.e., prices and costs as of the date the estimate is made). Proved developed oil and gas reserves are reserves that can 

be expected to be recovered through existing wells with existing equipment and operating methods. Undeveloped oil and gas reserves are reserves 

of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure 

is required for recompletion. Reserves on 

F- 46 

 For the Year Ended December 31, 

 2011 2010 2009 

 (in thousands, except per Mcfe data) 

Natural gas and oil sales, including unrealized natural gas hedge $ 40,235 $ 42,768 $ 32,869 

Production expenses (13,751 ) (11,703 ) (8,558 ) 

Impairment of natural gas and oil properties — — (68,729 ) 

Depreciation, depletion and amortization (14,989 ) (9,131 ) (16,331 ) 

Results of producing activities $ 11,495 $ 21,934 $ (60,749 ) 

Depreciation, depletion and amortization per Mcfe $ 1.95 

 $ 1.19  $ 1.76 

 As of December 31, 

 2011 2010 

Natural gas (per MMBtu): 

Henry Hub $ 4.12 $ 4.38 

Katy Hub $ 4.07 $ 4.32 

CIG $ 3.93 $ 3.95 

Columbia Gas Appalachia $ 4.20 $ 4.50 

Oil (per Bbl): 

per NSAI - WTI posting $ 92.71 $ 75.96 

per Wright - WTI spot $ 96.19 —

Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, 

unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled 

locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be 

drilled within five years, unless the specific circumstances, justify a longer time. The Company’s proved developed and proved undeveloped 

reserves are located only in the U.S.. 

F- 47 
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, 2011 , 2010 and 2009 : 

Change in Proved Reserves 

 

_______________ 

F- 48 

 

Natural Gas 

(MMcf) (1) 

NGLs 

(MBbl) (2) 

Oil 

(MBbl) (2) 

MMcfe (1) 

Equivalents (3) 

Proved reserves as of December 31, 2008 63,685 — 12 63,757 

2009 Activity: 

Extensions and discoveries 1,716 — 56 2,052 

Revisions of previous estimates (4) (7,603 ) — 3 (7,585 ) 

Production (9,266 ) — (4 ) (9,290 ) 

Proved reserves as of December 31, 2009 48,532 — 67 48,934 

2010 Activity: 

Extensions and discoveries 5,639 — 67 6,039 

Revisions of previous estimates 2,837 — (44 ) 2,576 

Production (7,593 ) — (10 ) (7,654 ) 

Purchases in place 1,527 — 6 1,565 

Sales in place (1,050 ) — (25 ) (1,200 ) 

Proved reserves as of December 31, 2010 49,892 — 61 50,260 

2011 Activity: 

Extensions and discoveries 56,364 2,767 1,945 84,634 

Revisions of previous estimates (5) (7,286 ) 11 (45 ) (7,494 ) 

Production (7,318 ) (21 ) (40 ) (7,684 ) 

Proved reserves as of December 31, 2011 91,652  2,757  1,921  119,716 

(1) Million cubic feet or million cubic feet equivalent, as applicable 

(2) Thousand barrels 

(3) Oil and NGLs volumes have been converted to equivalent natural gas volumes using a conversion factor of six cubic feet of natural gas to one 

barrel of oil or one barrel of NGLs. 

(4) The 2009 downward revision of previous estimates of natural gas is primarily attributable to lower natural gas prices. The December 31, 2009 

reserve report utilized a 12-month unweighted first-day-of-the-month price compared to the utilization of the year end spot price on 

December 31, 2008 resulting in a decrease in price of approximately 35% and a decrease in proved reserves of approximately 11,300 MMcf 

from December 31, 2008 to December 31, 2009. Natural gas negative impact was partially offset by upward performance revisions, primarily 

in the Hilltop area of East Texas. 

(5) The 2011 downward revision of previous estimates of natural gas is primarily attributed to the decision to forgo an East Texas PUD location 

due to low natural gas prices which would have resulted in drilling beyond the five-year maximum carry period. 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

Proved Developed and Undeveloped Reserves 

 

_______________ 

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

Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are 

discussed below. The Company believes that such information is essential for a proper understanding and assessment of the data presented. 

For the years ended December 31, 2011 , 2010 and 2009 future cash inflows were computed using the 12-month unweighted arithmetic 

average of the first-day-of-the-month prices for natural gas and oil relating to the Company’s proved reserves to the year-end quantities of those 

reserves. For the years ended December 31, 2011 , 2010 and 2009 , calculations were made using prices of $ 4.12 per MMBtu, $4.38 per MMBtu 

and $3.87 per MMBtu for natural gas, respectively, and $ 92.71 per barrel, $75.96 per barrel and $57.65 per barrel for oil, respectively. These prices 

are held constant in accordance with SEC guidelines for the life of the wells included in the reserve report but are adjusted by lease in accordance 

with sales contracts and for energy content, quality, transportation, compression and gathering fees and regional price differentials. The Company 

also includes its standard overhead charges pursuant to the respective property joint operating agreements in the calculation of its future cash flows. 

The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or 

costs, nor their present worth. In addition, variations from the expected production rate could also result directly or indirectly from factors outside 

of the Company’s control, such as unexpected delays in development, changes in prices or changes in regulatory or environmental policies. The 

reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic 

considerations could also affect the amount of cash eventually realized. 

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved 

oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. 

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates 

already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Permanent differences in oil and gas 

related tax credits and allowances are recognized. 

F- 49 

 

Natural Gas 

(MMcf) (1) 

NGLs 

(MBbl) (2) 

Oil 

(MBbl) (2) 

MMcfe (1) 

Equivalents (3) 

December 31, 2009 

Proved developed reserves 35,527 — 34 35,731 

Proved undeveloped reserves 13,005 — 33 13,203 

Total 48,532 — 67 48,934 

December 31, 2010 

Proved developed reserves 41,572 — 45 41,842 

Proved undeveloped reserves 8,320 — 16 8,416 

Total 49,892 — 61 50,258 

December 31, 2011 

Proved developed reserves 65,061 1,339 904 78,518 

Proved undeveloped reserves 26,591 1,418 1,017 41,198 

Total 91,652  2,757  1,921  119,716 

(1) Million cubic feet or million cubic feet equivalent, as applicable 

(2) Thousand barrels 

(3) Oil and NGLs volumes have been converted to equivalent natural gas volumes using a conversion factor of six cubic feet of natural gas to one 

barrel of oil or one barrel of NGLs. 
Table of Contents 

Index to Financial Statements 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 

A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves. 

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

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

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

The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is presented below: 

 

 _______________ 

F- 50 

 United States 

 (in thousands) 

December 31, 2009: 

Future cash inflows $ 148,002 

Future production costs (57,949 ) 

Future development costs (24,099 ) 

Future income taxes (1) —

Future net cash flows 65,954 

10% annual discount for estimated timing of cash flows (20,331 ) 

Standardized measure of discounted future cash flows $ 45,623 

December 31, 2010: 

Future cash inflows $ 180,677 

Future production costs (61,249 ) 

Future development costs (20,699 ) 

Future income taxes (1) —

Future net cash flows 98,729 

10% annual discount for estimated timing of cash flows (31,447 ) 

Standardized measure of discounted future cash flows $ 67,282 

December 31, 2011: 

Future cash inflows $ 584,067 

Future production costs (101,938 ) 

Future development costs (57,843 ) 

Future income taxes (33,732 ) 

Future net cash flows 390,554 

10% annual discount for estimated timing of cash flows (177,771 ) 

Standardized measure of discounted future cash flows $ 212,783 

(1) Based on current tax carry forwards and current and future property tax basis, no future taxes payable have been included in the determination 

of discounted future net cash flows. 
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- 51 

 United States 

 (in thousands) 

December 31, 2008 $ 110,089 

Extensions and discoveries, less related costs 2,782 

Sale of natural gas and oil, net of production costs (32,078 ) 

Revisions of previous quantity estimates (8,982 ) 

Net change in income tax —

Net change in prices and production costs (63,016 ) 

Accretion of discount 11,009 

Development costs incurred 12,368 

Net change in estimated future development costs 12,497 

Change in production rates (timing) and other 954 

December 31, 2009 45,623 

Extensions and discoveries, less related costs 10,277 

Sale of natural gas and oil, net of production costs (19,851 ) 

Purchases of reserves in place 544 

Sales of reserves in place (1,966 ) 

Revisions of previous quantity estimates 3,133 

Net change in income tax —

Net change in prices and production costs 16,970 

Accretion of discount 4,307 

Development costs incurred 6,357 

Net change in estimated future development costs 1,621 

Change in production rates (timing) and other 267 

December 31, 2010 $ 67,282 

Extensions and discoveries, less related costs 180,539 

Sale of natural gas and oil, net of production costs (24,148 ) 

Revisions of previous quantity estimates (9,323 ) 

Net change in income tax (4,334 ) 

Net change in prices and production costs 12,394 

Accretion of discount 5,011 

Development costs incurred 1,482 

Net change in estimated future development costs 4,541 

Change in production rates (timing) and other (20,661 ) 

December 31, 2011 $ 212,783 
Exhibit 21.1 

GASTAR EXPLORATION LTD. 

Subsidiary List - December 31, 2011 

100% Subsidiaries owned of Gastar Exploration Ltd. (Alberta, Canada) 

Gastar Exploration USA, Inc. (Delaware) 

100% Subsidiaries owned of Gastar Exploration USA, Inc. (Delaware) 

Gastar Exploration New South Wales, Inc. (Michigan) 

Gastar Exploration Victoria, Inc. (Michigan) 

Gastar Exploration Texas LP (Delaware) (1)(2) 

 

(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 (No. 333-174552-01) and Form S-8 (Nos. 333-

139112 and 333-159882) of Gastar Exploration, Ltd. of our reports dated March 8, 2012, relating to the consolidated financial statements of Gastar 

Exploration Ltd., and the effectiveness of Gastar Exploration, Ltd.'s internal control over financial reporting, which appear in this Annual Report on 

Form 10-K. 

BDO USA, LLP 

Dallas, TX 

March 8, 2012 
Exhibit 23.2 

Consent of Independent Registered Public Accounting Firm 

Gastar Exploration USA, Inc. 

Houston, Texas 

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-174552-01) of Gastar Exploration USA, 

Inc. of our report dated March 8, 2012, relating to the consolidated financial statements of Gastar Exploration USA, Inc., which appear in this 

Annual Report on Form 10-K. 

BDO USA, LLP 

Dallas, TX 

March 8, 2012 
EXHIBIT 23.3 

CONSENT OF WRIGHT & COMPANY, INC. 

We hereby consent to the references to our firm, in the context in which they appear, and to the references to and incorporation of our 

report dated January 19, 2012, included in the Annual Report on Form 10-K of Gastar Exploration Ltd. for the fiscal year ended 

December 31, 2011, as well as in the notes to the financial statements included therein. 

Wright & Company, Inc. 

TX. Reg. No. F-12302 

By: /s/ D. Randall Wright 

D. Randall Wright, P.E. 

President 

Brentwood, Tennessee 

March 8, 2012 
Exhibit 23.4 

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS 

We hereby consent to the references to our firm, in the context in which they appear, and to the references to and incorporation of our 

report dated January 23, 2012, included in the Annual Report on Form 10-K of Gastar Exploration Ltd. for the fiscal year ended 

December 31, 2011, as well as in the notes to the financial statements included therein. 

NETHERLAND, SEWELL & ASSOCIATES, INC. 

 

/s/ C.H. (Scott) Rees III 

By: 

C.H. (Scott) Rees III, P.E. 

Chairman and Chief Executive Officer 

Dallas, Texas 

March 8, 2012 
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 8, 2012 

1. I have reviewed this Annual 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 8, 2012 

1. I have reviewed this Annual 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 31.3 

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 8, 2012 

1. I have reviewed this Annual Report on Form 10-K of Gastar Exploration USA, Inc. (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 

 President 
Exhibit 31.4 

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 8, 2012 

1. I have reviewed this Annual Report on Form 10-K of Gastar Exploration USA, Inc. (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 

 Treasurer 
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 the period ended December 31, 2010 (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, as amended, 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 8, 2012 

 /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 the period ended December 31, 2010 (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, as amended, 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 8, 2012 

 /s/ MICHAEL A. GERLICH 

 Michael A. Gerlich 

 Chief Financial Officer 
Exhibit 32.3 

Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 

I, J. Russell Porter, President of Gastar Exploration USA, Inc. (the “Company”), hereby certify that the accompanying Annual Report on 

Form 10-K for the period ended December 31, 2010 (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, as amended, 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 8, 2012 

 /s/ J. RUSSELL PORTER 

 J. Russell Porter 

 President 
Exhibit 32.4 

Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 

I, Michael A. Gerlich, Treasurer of Gastar Exploration USA, Inc. (the “Company”), hereby certify that the accompanying Annual Report on 

Form 10-K for the period ended December 31, 2010 (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, as amended, 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 8, 2012 

 /s/ MICHAEL A. GERLICH 

 Michael A. Gerlich 

 Treasurer 
 

January 23, 2012 

Mr. J. Russell Porter 

Gastar Exploration Ltd. 

1331 Lamar Street, Suite 1080 

Houston, Texas 77010 

Dear Mr. Porter: 

In accordance with your request, we have estimated the proved and probable reserves and future revenue, as of December 31, 2011, 

to the Gastar Exploration Ltd. (Gastar) interest in certain oil and gas properties located in Texas, Wyoming, and Kansas. We 

completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report 

constitute approximately 30 percent of all proved reserves owned by Gastar. The estimates in this report have been prepared in 

accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the 

exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and 

Gas. Definitions are presented immediately following this letter. This report has been prepared for Gastar's use in filing with the SEC; 

in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose. 

We estimate the net reserves and future net revenue to the Gastar interest in these properties, as of December 31, 2011, to be: 

The oil reserves shown include crude oil and condensate. Oil volumes are expressed in barrels that are equivalent to 42 United States 

gallons. Gas volumes are expressed in thousands of cubic feet (MCF) at standard temperature and pressure bases. 

The estimates shown in this report are for proved and probable reserves. As requested, possible reserves that exist for these 

properties have not been included. This report does not include any value that could be attributed to interests in undeveloped acreage 

beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of 

certainty; reserves subcategorization is based on 

 

 Net Reserves Future Net Revenue ($) 

 Oil Gas Present Worth 

Category (Barrels) (MCF) Total at 10% 

 

Proved Developed Producing 6,705 27,368,738 47,873,300 32,616,800 

Proved Developed Non-Producing 0 8,273,124 14,884,200 10,160,400 

Proved Undeveloped (1)  0 0 0 0 

Total Proved 6,705 35,641,862 62,757,500 42,777,200 

 

Probable Developed 2,365 7,517,324 17,607,600 11,441,200 

Probable Undeveloped 0 37,586,384 54,029,700 21,297,500 

Total Probable 2,365 45,103,708 71,637,300 32,738,700 

(1) 

 There are no proved undeveloped reserves at the prices and costs used in this report. 
 

development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk. 

Gross revenue is Gastar's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is 

after deductions for Gastar's share of production taxes and ad valorem taxes, capital costs, abandonment costs, and operating 

expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent 

to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in 

this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties. 

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month 

in the period January through December 2011. For gas volumes, the average regional spot prices are adjusted by lease for energy 

content and local price differentials. For oil volumes, the average West Texas Intermediate (WTI) posted price is adjusted by lease for 

quality, transportation fees, and a regional price differential. All prices are held constant throughout the lives of the properties. For the 

proved reserves, the average adjusted product prices weighted by production over the remaining lives of the properties are $3.289 per 

MCF of gas and $88.46 per barrel of oil. Average index prices along with the average realized prices for each state are shown in the 

following table: 

Operating costs used in this report are based on operating expense records of Gastar. These costs include the per-well overhead 

expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field 

levels. Headquarters general and administrative overhead expenses of Gastar are included to the extent that they are covered under 

joint operating agreements for the operated properties. Operating costs are held constant throughout the lives of the properties. 

Capital costs used in this report were provided by Gastar and are based on authorizations for expenditure and actual costs from 

recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our 

understanding of Gastar's future development plans, a review of the records provided to us, and our knowledge of similar properties, 

we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Gastar's estimates of the costs 

to abandon the wells, platforms, and production facilities, net of any salvage value. Capital costs and abandonment costs are held 

constant to the date of expenditure. 

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation 

or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our 

estimates do not include any costs due to such possible liability. 

 Gas Oil 

 Pricing 

Average 

Spot Price 

Average 

Realized Price Pricing 

Average 

Posted Price 

Average 

Realized Price 

Area Index ($/MMBTU) ($/MCF) Index ($/Barrel) ($/Barrel) 

 

Texas Katy 4.074 3.284 WTI 92.71 88.46 

 

Wyoming 

 

CIG Rocky 

Mountains 

3.927 

 

3.436 

 

N/A 

 

-- 

 

-- 

 

Kansas Henry Hub 4.118 3.014 N/A -- -- 
 

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the 

Gastar interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such 

imbalances; our projections are based on Gastar receiving its net revenue interest share of estimated future gross gas production. 

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those 

quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be 

economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be 

recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, 

changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our 

estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current 

development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in 

place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove 

consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more 

or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices 

received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this 

report. 

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic 

data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report 

have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining 

to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE 

Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, 

volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in 

accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the 

interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional 

judgment. 

The data used in our estimates were obtained from Gastar, public data sources, and the nonconfidential files of Netherland, Sewell & 

Associates, Inc. (NSAI) and were accepted as accurate. Supporting geoscience, performance, and work data are on file in our office. 

The titles to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently 

confirmed. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding 

qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, 

geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent 

basis. 

Sincerely, 

NETHERLAND, SEWELL & ASSOCIATES, INC. 

Texas Registered Engineering Firm F-2699 

/s/ C.H. (Scott) Rees III 

By: 

C.H. (Scott) Rees III, P.E. 

Chairman and Chief Executive Officer 
 

/s/ Dan Paul Smith /s/ William J. Knights 

By: By: 

Dan Paul Smith, P.E. 49093 William J. Knights, P.G. 1532 

Senior Vice President Vice President 

Date Signed: January 23, 2012 Date Signed: January 23, 2012 

WKB:SDB 

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DEFINITIONS OF OIL AND GAS RESERVES 

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) 

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also 

included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of 

Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the 

SEC's Compliance and Disclosure Interpretations. 

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and 

options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in 

fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties. 

(2) Analogous reservoir . Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir 

conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than 

the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. 

When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the 

reservoir of interest: 

Instruction to paragraph (a)(2) : Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir 

of interest. 

(3) Bitumen . Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a 

viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free 

basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons. 

(4) Condensate . Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and 

pressure, but that, when produced, is in the liquid phase at surface pressure and temperature. 

(5) Deterministic estimate . The method of estimating reserves or resources is called deterministic when a single value for each 

parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation 

procedure. 

(6) Developed oil and gas reserves . Developed oil and gas reserves are reserves of any category that can be expected to be 

recovered: 

Definitions - Page 1 

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest); 

(ii) Same environment of deposition; 

(iii) Similar geological structure; and 

(iv) Same drive mechanism. 

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is 

relatively minor compared to the cost of a new well; and 

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is 

by means not involving a well. 
 

DEFINITIONS OF OIL AND GAS RESERVES 

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) 

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering 

and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support 

equipment and facilities and other costs of development activities, are costs incurred to: 

(8) Development project . A development project is the means by which petroleum resources are brought to the status of economically 

producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the 

integrated development of a group of several fields and associated facilities with a common ownership may constitute a development 

project. 

(9) Development well . A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to 

be productive. 

(10) Economically producible . The term economically producible, as it relates to a resource, means a resource which generates 

revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate 

revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section. 

(11) Estimated ultimate recovery (EUR) . Estimated ultimate recovery is the sum of reserves remaining as of a given date and 

cumulative production as of that date. 

(12) Exploration costs . Costs incurred in identifying areas that may warrant examination and in examining specific areas that are 

considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type 

stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as 

prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable 

operating costs of support equipment and facilities and other costs of exploration activities, are: 

Definitions - Page 2 

 

Supplemental definitions from the 2007 Petroleum Resources Management System: 

 

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and 

producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation. 

 

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are 

expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) 

wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe 

Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to 

start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. 

 

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific 

development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to 

the extent necessary in developing the proved reserves. 

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of 

platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly. 

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, 

measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste 

disposal systems. 

(iv) Provide improved recovery systems. 
 

DEFINITIONS OF OIL AND GAS RESERVES 

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) 

(13) Exploratory well . An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be 

productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension 

well, a service well, or a stratigraphic test well as those items are defined in this section. 

(14) Extension well . An extension well is a well drilled to extend the limits of a known reservoir. 

(15) Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological 

structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by 

intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping 

or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic 

condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, 

areas-of-interest, etc. 

(16) Oil and gas producing activities. 

Instruction 1 to paragraph (a)(16)(i) : The oil and gas production function shall be regarded as ending at a "terminal point", which 

is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate 

to regard the terminal point for the production function as: 

Definitions - Page 3 

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and 

salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are 

sometimes referred to as geological and geophysical or "G&G" costs. 

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for 

title defense, and the maintenance of land and lease records. 

(iii) Dry hole contributions and bottom hole contributions. 

(iv) Costs of drilling and equipping exploratory wells. 

(v) Costs of drilling exploratory-type stratigraphic test wells. 

(i) Oil and gas producing activities include: 

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states 

and original locations; 

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil 

or gas from such properties; 

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including 

the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: 

(1) Lifting the oil and gas to the surface; and 

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and 

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other 

nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken 

with a view to such extraction. 

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a 

refinery, or a marine terminal; and 

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are 

delivered to a purchaser prior to upgrading, the first point at which the natural resources 
 

DEFINITIONS OF OIL AND GAS RESERVES 

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) 

are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural 

resources into synthetic oil or gas. 

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons 

that are saleable in the state in which the hydrocarbons are delivered. 

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. 

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves 

but which, together with proved reserves, are as likely as not to be recovered. 

Definitions - Page 4 

(ii) Oil and gas producing activities do not include: 

(A) Transporting, refining, or marketing oil and gas; 

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that 

does not have the legal right to produce or a revenue interest in such production; 

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil 

and gas can be extracted; or 

(D) Production of geothermal steam. 

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of 

exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% 

probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves 

estimates. 

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and 

interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and 

engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a 

defined project. 

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in 

place than the recovery quantities assumed for probable reserves. 

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable 

alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, 

including comparisons to results in successful similar projects. 

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir 

within the same accumulation that may be separated from proved areas by faults with displacement less than formation 

thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that 

such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas 

that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. 

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation 

and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of 

the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable 

technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and 

possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. 

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of 

estimated proved plus probable reserves. When probabilistic methods are used, 
 

DEFINITIONS OF OIL AND GAS RESERVES 

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) 

there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable 

reserves estimates. 

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that 

could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of 

possible outcomes and their associated probabilities of occurrence. 

(20) Production costs. 

(21) Proved area. The part of a property to which proved reserves have been specifically attributed. 

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience 

and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from 

known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which 

contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether 

deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or 

the operator must be reasonably certain that it will commence the project within a reasonable time. 

Definitions - Page 5 

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations 

of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the 

reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if 

these areas are in communication with the proved reservoir. 

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of 

the hydrocarbons in place than assumed for proved reserves. 

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. 

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable 

operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related 

equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes 

called lifting costs) are: 

(A) Costs of labor to operate the wells and related equipment and facilities. 

(B) Repairs and maintenance. 

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. 

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. 

(E) Severance taxes. 

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve 

transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas 

producing activities, their depreciation and applicable operating costs become exploration, development or production costs, 

as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are 

not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified 

above. 

(i) The area of the reservoir considered as proved includes: 

(A) The area identified by drilling and limited by fluid contacts, if any, and 
 

DEFINITIONS OF OIL AND GAS RESERVES 

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) 

(23) Proved properties. Properties with proved reserves. 

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the 

quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually 

recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than 

not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and 

economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or 

remain constant than to decrease. 

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has 

been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation 

being evaluated or in an analogous formation. 

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically 

producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there 

must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed 

means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. 

Note to paragraph (a)(26) : Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until 

those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly 

separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative 

test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered 

accumulations). 

Definitions - Page 6 

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to 

contain economically producible oil or gas on the basis of available geoscience and engineering data. 

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) 

as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a 

lower contact with reasonable certainty. 

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for 

an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if 

geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. 

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited 

to, fluid injection) are included in the proved classification when: 

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a 

whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable 

technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; 

and 

(B) The project has been approved for development by all necessary parties and entities, including governmental entities. 

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. 

The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, 

determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless 

prices are defined by contractual arrangements, excluding escalations based upon future conditions. 
 

DEFINITIONS OF OIL AND GAS RESERVES 

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) 

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is 

confined by impermeable rock or water barriers and is individual and separate from other reservoirs. 

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the 

resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both 

discovered and undiscovered accumulations. 

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service 

wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or 

injection for in-situ combustion. 

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a 

specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The 

classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. 

Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area. 

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be 

recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for 

recompletion. 

Definitions - Page 7 

 

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas: 

 

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be 

disclosed as of the end of the year: 

a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B) 

b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in 

the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 

932-235-50-7). 

 

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for 

reporting purposes. 

 

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities 

are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B: 

a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the yearend quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in 

existence at year-end. 

b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing 

and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing 

economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated 

production costs. 

c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with 

consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, 

less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and 

allowances relating to the entity's proved oil and gas reserves. 

d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax 

expenses from future cash inflows. 

e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows 

relating to proved oil and gas reserves. 

f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. 
 

DEFINITIONS OF OIL AND GAS RESERVES 

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) 

(32) Unproved properties. Properties with no proved reserves. 

Definitions - Page 8 

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably 

certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of 

economic producibility at greater distances. 

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating 

that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. 

 

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009): 

 

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or 

environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time 

periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se 

justifies a longer time period, and any extension beyond five years should be the exception, and not the rule. 

 

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though 

development may extend past five years include, but are not limited to, the following: 

. The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the 

minimum number of wells necessary to maintain the lease generally would not constitute significant development activities); 

. The company's historical record at completing development of comparable long-term projects; 

. The amount of time in which the company has maintained the leases, or booked the reserves, without significant development 

activities; 

. The extent to which the company has followed a previously adopted development plan (for example, if a company has changed 

its development plan several times without taking significant steps to implement any of those plans, recognizing proved 

undeveloped reserves typically would not be appropriate); and 

. The extent to which delays in development are caused by external factors related to the physical operating environment (for 

example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors 

(for example, shifting resources to develop properties with higher priority). 

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of 

fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by 

actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other 

evidence using reliable technology establishing reasonable certainty. 
Mr. J. Russell Porter 

Gastar Exploration Ltd. 

January 19, 2012 

Page 1 

January 19, 2012 

Gastar Exploration Ltd.1331 Lamar, Suite 650 

Houston, TX 77010 

Attention: Mr. J. Russell Porter 

SUBJECT: Evaluation of Oil and Gas Reserves 

To the Interests of Gastar Exploration Ltd. 

In Certain Properties Located in 

Pennsylvania and West Virginia 

Pursuant to the Requirements of the 

Securities and Exchange Commission 

Effective January 1, 2012 

Job 11.1341 

At the request of Gastar Exploration Ltd. (Gastar), Wright & Company, Inc. (Wright) has performed an evaluation 

to estimate proved reserves and associated cash flow and economics from certain properties to the subject interests. This 

evaluation was authorized by Mr. J. Russell Porter of Gastar. Projections of the reserves and cash flow to the evaluated 

interests were based on specified economic parameters, operating conditions, and government regulations considered 

applicable at the effective date. This reserves evaluation is pursuant to the financial reporting requirements of the Securities 

and Exchange Commission (SEC) as specified in Regulation S-X, Rule 4-10(a) and Regulation 

S-K, Rule 1202(a)(8). It is the understanding of Wright that the purpose of this evaluation is for inclusion in relevant 

registration statements or other filings to the SEC. The effective date of this report is January 1, 2012. The report was 

completed January 19, 2012. The following is a summary of the results of the evaluation. 

It should be noted that some minor differences might exist between the total summaries and the table totals due to rounding techniques in the ARIES TM petroleum 

software program. 

Gastar Exploration Ltd. 

SEC Parameters 

Proved Developed Total 

Proved Developed 

(PDP & PDNP) 

Proved 

Undeveloped 

(PUD) 

Total 

Proved 

(PDP, PDNP & PUD) 

Producing 

(PDP) 

Nonproducing 

(PDNP) 

Net Reserves to the 

Evaluated Interests 

Oil, Mbbl: 721.809 175.437 897.246 1,016.672 1,913.918 

Gas, MMcf: 22,027.881 7,391.207 29,419.086 26,591.324 56,010.406 

NGL, Mbbl: 1,075.146 263.78 1,338.926 1,417.694 2,756.62 

Gas Equivalent, MMcfe: 32,809.611 10,026.509 42,836.118 41,197.52 84,033.634 

(1 bbl = 6 Mcfe) 

Cash Flow (BTAX), M$ 

Undiscounted: 157,680.75 40,308.988 197,989.734 163,539.281 361,529.031 

Discounted at 10% 

Per Annum: 85,653.359 21,415.092 107,068.484 67,271.32 174,339.797 
Mr. J. Russell Porter 

Gastar Exploration Ltd. 

January 19, 2012 

Page 2 

The properties evaluated in this report are located in the states of Pennsylvania and West Virginia. According to 

Gastar, the total proved reserves included in this evaluation represent approximately 70 percent of the reported total proved 

reserves of Gastar. 

 

Proved oil and gas reserves are those quantities of oil and gas which can be estimated with reasonable certainty to 

be economically producible under existing economic conditions, operating methods, and government regulations. As 

specified by the SEC regulations, when calculating economic producibility, the base product price must be the 12-month 

average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within 

the prior 12-month period. The benchmark base prices used for this evaluation were $96.19 per barrel for West Texas

Intermediate oil at Cushing, OK and $4.118 per Million British thermal units (MMBtu) for natural gas at Henry Hub, LA. 

These benchmark base prices were adjusted for contract terms, energy content, quality, and basis differential, as 

appropriate. The average adjusted product prices used to estimate proved reserves are $67.46 per barrel of oil and $3.696 

per Mcf of gas. Prices for oil and gas were held constant for the life of the properties. The Natural Gas Liquids (NGL) 

product price was estimated to be approximately 49 percent of the base oil price, resulting in an average adjusted price of 

$47.21 per barrel. 

Oil and other liquid hydrocarbons are expressed in thousands of United States (U.S.) barrels (Mbbl), one barrel 

equaling 42 U.S. gallons. Gas volumes are expressed in millions of standard cubic feet (MMcf) at 60 degrees Fahrenheit 

and at the legal pressure base that prevails in the state in which the reserves are located. No adjustment of the individual 

gas volumes to a common pressure base has been made. 

Net income to the evaluated interests is the cash flow after consideration of royalty revenue payable to others, 

standard state and county taxes, operating expenses, and investments, as applicable. The cash flow is before federal income 

tax (BTAX) and excludes consideration of any encumbrances against the properties if such exist. The cash flow (BTAX) 

was discounted at an annual rate of 10.00 percent (PCT) in accordance with the reporting requirements of the SEC. 

The estimates of reserves contained in this report were determined by accepted industry methods, and the 

procedures used in this evaluation are appropriate for the purpose served by the report. Where sufficient production history 

and other data were available, reserves for producing properties were determined by extrapolation of historical production 

or sales trends. Analogy to similar producing properties was used for development projects and for those properties that 

lacked sufficient production history to yield a definitive estimate of reserves. When appropriate, Wright may have also 

utilized volumetric calculations and log correlations in the determination of estimated ultimate recovery (EUR). These 

calculations are often based upon limited log and/or core analysis data and incomplete formation fluid and rock data. Since 

these limited data must frequently be extrapolated over an assumed drainage area, subsequent production performance 

trends or material balance calculations may cause the need for significant revisions to the estimates of reserves. Wright has 

used all methods and procedures as it considered necessary under the circumstances to prepare this report. 
Mr. J. Russell Porter 

Gastar Exploration Ltd. 

January 19, 2012 

Page 3 

Oil and gas reserves were evaluated for the proved developed producing (PDP), proved developed nonproducing 

(PDNP) and proved undeveloped (PUD) reserves categories. The summary classification of total proved reserves combines 

the PDP, PDNP and PUD categories. In preparing this evaluation, no attempt has been made to quantify the element of 

uncertainty associated with any category. Reserves were assigned to each category as warranted. Wright is not aware of 

any local, state, or federal regulations that would preclude Gastar from continuing to produce from currently active wells or 

to fully develop those properties included in this report. 

There are significant uncertainties inherent in estimating reserves, future rates of production, and the timing and 

amount of future costs. The estimation of oil and gas reserves must be recognized as a subjective process that cannot be 

measured in an exact way, and estimates of others might differ materially from those of Wright. The accuracy of any 

reserves estimate is a function of the quantity and quality of available data and of subjective interpretations and judgments. 

It should be emphasized that production data subsequent to the date of these estimates or changes in the analogous 

properties may warrant revisions of such estimates. Accordingly, reserves estimates are often different from the quantities 

of oil and gas that are ultimately recovered. 

All data utilized in the preparation of this report were provided by Gastar. No inspection of the properties was made 

as this was not considered to be within the scope of this evaluation. Wright has not independently verified the accuracy and 

completeness of information and data furnished by Gastar with respect to ownership interests, oil and gas production or 

sales, historical costs of operation and development, product prices, or agreements relating to current and future operations 

and sales of production. Wright requested and received detailed information allowing Wright to check and confirm any 

calculations provided by Gastar with regard to product pricing, appropriate adjustments, lease operating expenses, and 

capital investments for drilling the undeveloped locations. Furthermore, if in the course of Wright’s examination something 

came to our attention that brought into question the validity or sufficiency of any information or data, Wright did not rely 

on such information or data until we had satisfactorily resolved our questions relating thereto or independently verified 

such information or data. In accordance with the requirements of the SEC, all operating costs were held constant for the life 

of the properties. 

Wright is not aware of any potential environmental liabilities that may exist concerning the properties evaluated. 

There are no costs included in this evaluation for potential property restoration, liability, or clean up of damages, if any, 

that may be necessary due to past or future operating practices. 

Wright is an independent petroleum consulting firm founded in 1988 and owns no interests in the oil and gas 

properties covered by this report. No employee, officer, or director of Wright is an employee, officer, or director of Gastar, 

nor does Wright or any of its employees have direct financial interest in Gastar. Neither the employment of nor the 

compensation received by Wright is contingent upon the values assigned or the opinions rendered regarding the properties 

covered by this report. 

This report is prepared for the information of Gastar, its shareholders, and for the information and 
Mr. J. Russell Porter 

Gastar Exploration Ltd. 

January 19, 2012 

Page 4 

assistance of its independent public accountants in connection with their review of and report upon the financial statements 

of Gastar, and for reporting disclosures as required by the SEC. This report is also intended for public disclosure as an 

exhibit in filings made to the SEC by Gastar. 

Based on data and information provided by Gastar, and the specified economic parameters, operating conditions, 

and government regulations considered applicable at the effective date, it is Wright’s conclusion that this report provides a 

fair and accurate representation of the oil and gas reserves to the interests of Gastar in those certain properties included in 

this report. 

The professional qualifications of the petroleum consultants responsible for the evaluation of the reserves and 

economics information presented in this report meet the standards of Reserves Estimator as defined in the Standards 

Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of 

Petroleum Engineers. 

It has been a pleasure to serve you by preparing this evaluation. All related data will be retained in our files and are 

available for your review. 

Very truly yours, 

Wright & Company, Inc. 

TX Reg. No. F-12302 

By: /s/ D. Randall Wright ________ 

D. Randall Wright 

President 

DRW/EKL/RDP/SDW/ts 

3_SEC Letter 

Job 11.1341