Final Prospectus
Table of Contents
Index to Financial Statements

Filed pursuant to Rule 424(b)(4)
SEC File No. 333-176263

 

PROSPECTUS

13,333,334 Shares

LOGO

Matador Resources Company

Common Stock

 

 

Matador Resources Company is offering 11,666,667 shares of its common stock, and the selling shareholders are offering 1,666,667 shares of our common stock. This is our initial public offering, and no public market currently exists for our shares. We will not receive any of the proceeds from the sale of shares by the selling shareholders.

Our common stock has been approved for listing on the New York Stock Exchange under the symbol “MTDR.”

Investing in our common stock involves risks. See “Risk Factors” beginning on page 23.

 

 

PRICE $12.00 PER SHARE

 

 

 

      Price to Public      Underwriting
Discounts and
Commissions(1)
     Proceeds to
Company
     Proceeds to
Selling Shareholders(1)
 

Per Share

   $ 12.00       $ 0.81       $ 11.19       $ 11.19   

Total

   $ 160,000,008       $ 10,602,798       $ 130,550,004       $ 18,847,206   

 

  (1)

Certain selling shareholders that are selling 243,460 shares in this offering will not be required to pay underwriting discounts or commissions. See “Underwriters” for additional information.

We have granted the underwriters the right to purchase up to an additional 700,000 shares of common stock to cover over-allotments. The selling shareholders have granted the underwriters the right to purchase up to 1,300,000 additional shares to cover over-allotments.

The Securities and Exchange Commission and state securities regulators have not approved or disapproved of these securities, or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the shares of common stock to purchasers on February 7, 2012.

 

 

 

RBC CAPITAL MARKETS   CITIGROUP  
JEFFERIES
HOWARD WEIL INCORPORATED     STIFEL NICOLAUS WEISEL  

SIMMONS & COMPANY INTERNATIONAL

 

STEPHENS INC.

  COMERICA SECURITIES  

February 1, 2012


Table of Contents
Index to Financial Statements

LOGO


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

 

Prospectus Summary

     1   

Risk Factors

     23   

Cautionary Note Regarding Forward-Looking Statements

     48   

Use of Proceeds

     50   

Dividend Policy

     52   

Capitalization

     53   

Dilution

     54   

Selected Historical Consolidated and Other Financial Data

     55   

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

     57   

Business

     90   

Management

     130   

Compensation of Named Executive Officers

     143   

Certain Relationships and Related Party Transactions

     167   

Corporate Reorganization

     171   

Principal and Selling Shareholders

     173   

Description of Capital Stock

     179   

Shares Eligible for Future Sale

     183   

Material U.S. Federal Income and Estate Tax Considerations to Non-U.S. Holders

     185   

Underwriters (Conflicts of Interest)

     189   

Legal Matters

     198   

Experts

     198   

Where You Can Find More Information

     198   

Index to Financial Statements

     F-1   

Glossary of Oil and Natural Gas Terms

     A-1   

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by or on behalf of us or to which we have referred you. Neither we nor the selling shareholders have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We and the selling shareholders are offering to sell shares of common stock, and seeking offers to buy shares of common stock, only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common stock.

Until February 26, 2012, all dealers that buy, sell or trade our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Although we believe these third party sources are reliable and that the information is accurate and complete, we have not independently verified the information. Some data is also based on our good faith estimates.

 

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Index to Financial Statements

PROSPECTUS SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. You should read the entire prospectus carefully before making an investment decision, including the information presented under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and related notes thereto included elsewhere in this prospectus. Unless otherwise indicated, information presented in this prospectus assumes that the underwriters’ option to purchase additional common shares is not exercised. We have provided definitions for certain oil and natural gas terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms” beginning on page A-1 of this prospectus.

In this prospectus, unless the context otherwise requires, the terms “we,” “us,” “our,” and the “company” refer to Matador Resources Company and its subsidiaries before the completion of our corporate reorganization on August 9, 2011 and Matador Holdco, Inc. and its subsidiaries after the completion of our corporate reorganization on August 9, 2011. Prior to August 9, 2011, Matador Holdco, Inc. was a wholly owned subsidiary of Matador Resources Company, now known as MRC Energy Company. Pursuant to the terms of our corporate reorganization, former Matador Resources Company became a wholly owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its corporate name to Matador Resources Company. See “Organizational Structure” on page 14 and “Corporate Reorganization” on page 171 of this prospectus.

In this prospectus, unless the context otherwise requires, the term “common stock” refers to shares of our common stock after the conversion of our Class B common stock into Class A common stock upon the consummation of this offering, as the Class A common stock will be the only class of common stock authorized after this offering, and the term “Class A common stock” refers to shares of our Class A common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of this offering. See “Description of Capital Stock.” In addition, in this prospectus, we have assumed that 285,000 shares of common stock will be issued to certain holders of stock options prior to consummation of this offering and 243,460 of these shares will be sold by the option holders as selling shareholders in this offering.

Matador Resources Company

Overview

Matador Resources Company is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resource plays. Our current operations are located primarily in the Eagle Ford shale play in south Texas and the Haynesville shale play in northwest Louisiana and east Texas. These plays are a key part of our growth strategy, and we believe they currently represent two of the most active and economically viable unconventional resource plays in North America. We expect the majority of our near-term capital expenditures will focus on increasing our production and reserves from the Eagle Ford and Haynesville shale plays as we seek to capitalize on the relative economics of each play. In addition to these primary operating areas, we have acreage positions in

 

 

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Index to Financial Statements

southeast New Mexico and west Texas and in southwest Wyoming and adjacent areas in Utah and Idaho where we continue to identify new oil and natural gas prospects.

We were founded in July 2003 by Joseph Wm. Foran, Chairman, President and CEO, and Scott E. King, Co-Founder and Vice President, Geophysics and New Ventures, with an initial equity investment of approximately $6.0 million. Shortly thereafter, investors contributed approximately $46.8 million to provide a total initial capitalization of approximately $52.8 million. Most of this initial capital was provided by the same institutional and individual investors who helped capitalize Mr. Foran’s previous company, Matador Petroleum Corporation.

Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc. in an all cash transaction for an enterprise value of approximately $388.5 million.

With an average of more than 25 years of oil and natural gas industry experience, our management team has extensive expertise in exploring for and developing hydrocarbons in multiple U.S. basins. Members of our management team have participated in the assimilation of numerous lease positions and in the drilling and completion of hundreds of vertical and horizontal wells in unconventional resource plays.

Since our first well in 2004, we have drilled or participated in drilling 213 wells through September 30, 2011, including 83 Haynesville and six Eagle Ford wells. From December 31, 2008 through September 30, 2011, we grew our estimated proved reserves from 20.0 Bcfe to 161.8 Bcfe. At September 30, 2011, 35% of our estimated proved reserves were proved developed reserves and 96% of our estimated proved reserves were natural gas. We also grew our average daily production by approximately 162% from 9.0 MMcfe per day for the year ended December 31, 2008 to 23.6 MMcfe per day for the year ended December 31, 2010. In addition, as a result of production from new wells that were completed in 2011, our daily production for the nine months ended September 30, 2011 averaged approximately 42.5 MMcfe per day. We have achieved this growth while lowering operating costs (consisting of lease operating expenses and production taxes and marketing expenses) from $1.91 per Mcfe for the year ended December 31, 2008, to $0.90 per Mcfe for the nine months ended September 30, 2011, or a decrease of approximately 53%.

 

 

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Index to Financial Statements

The following table presents certain summary data for each of our operating areas as of and for the nine months ended September 30, 2011:

 

            Producing
Wells
    

Total Identified

Drilling  Locations(1)

     Estimated Net Proved
Reserves
     Avg. Daily
Production
(MMcfe)
 
     Net Acreage      Gross        Net          Gross          Net        Bcfe(2)      % Developed     

South Texas:

                       

Eagle Ford

     28,906         5.0         3.4         197.0         157.1         8.4         51.0         3.2   

Austin Chalk

     14,849                         16.0         16.0                           
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Area Total(3)

     28,906         5.0         3.4         213.0         173.1         8.4         51.0         3.2   

NW Louisiana/E Texas:

                       

Haynesville

     14,705         83.0         10.6         545.0         103.9         136.6         25.4         32.1   

Cotton Valley(4)

     23,236         108.0         71.7         60.0         36.0         16.1         100.0         7.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Area Total(5)

     25,477         191.0         82.3         605.0         139.9         152.7         33.3         39.1   

SW Wyoming, NE Utah, SE Idaho

     135,862                                                           

SE New Mexico, West Texas

     7,519         13.0         5.7                         0.7         100.0         0.2   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     197,764         209.0         91.4         818.0         313.0         161.8         34.5         42.5   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) These locations have been identified for potential future drilling and are not currently producing. In addition, the total net identified drilling locations is calculated by multiplying the gross identified drilling locations in an operating area by our working interest participation in such locations. At September 30, 2011, these identified drilling locations included 2 gross and 2 net locations to which we have assigned proved undeveloped reserves in the Eagle Ford and 95 gross and 15 net locations to which we have assigned proved undeveloped reserves in the Haynesville. We have no proved undeveloped reserves assigned to identified drilling locations in the Austin Chalk or Cotton Valley at September 30, 2011.

 

(2) These estimates were prepared by our engineering staff and audited by independent reservoir engineers, Netherland, Sewell & Associates, Inc.

 

(3) Some of the same leases cover the net acres shown for the Eagle Ford formation and the Austin Chalk formation, a shallower formation than the Eagle Ford formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for south Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations.

 

(4) Includes shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells producing from the San Miguel formation in Zavala County, Texas.

 

(5) Some of the same leases cover the net acres shown for the Haynesville formation and the Cotton Valley formation, a shallower formation than the Haynesville formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for northwest Louisiana/east Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations.

At September 30, 2011, our properties included approximately 52,000 gross acres and 29,000 net acres in the Eagle Ford shale play in Atascosa, DeWitt, Dimmit, Karnes, La Salle, Gonzales, Webb, Wilson and Zavala Counties in south Texas. We believe that approximately 85% of our Eagle Ford acreage is prospective predominantly for oil or liquids production. In addition, portions of the acreage are also prospective for other targets, such as the Austin Chalk, Olmos and Buda, from which we expect to produce predominantly oil and liquids. Approximately 80% of our Eagle Ford acreage is either held by production or not burdened by lease expirations before 2013. We have begun to explore and develop our Eagle Ford position and from November 2010 through December 2011, we completed our first seven operated wells in this area (see “— Recent Developments”). We have identified 197 gross locations and 157 net locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated recoveries from nearby wells based on available public data, drilling densities observed from other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among others. At September 30, 2011, we have identified potential drilling locations on approximately 75% of our net Eagle Ford acreage. As we

 

 

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Index to Financial Statements

explore and develop our Eagle Ford acreage further, we believe it is possible that we may identify additional locations for drilling. At September 30, 2011, these identified potential future drilling locations in the Eagle Ford shale play included 2 gross and 2 net locations to which we have assigned proved undeveloped reserves.

In addition, at September 30, 2011, we had approximately 23,000 gross acres and 15,000 net acres in the Haynesville shale play in northwest Louisiana and east Texas. Based on our analysis of geologic and petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data and information available to us related to drilling activity and results from wells drilled across the Haynesville shale play, almost 5,500 of our net acres are located in what we believe is the core area of the play. We believe the core area of the play includes that area in which the most Haynesville wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Just over 90% of our Haynesville acreage is held by production from the Haynesville or other formations, and we believe much of it is also prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe approximately 1,700 of these net acres are prospective for the Middle Bossier shale play.

At September 30, 2011, we have identified 545 gross locations and 104 net locations for potential future drilling in our Haynesville acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated recoveries from our producing Haynesville wells and other nearby wells based on available public data, drilling densities observed from other operators including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among others. Of the 545 gross locations identified for future drilling, 470 of these locations (53 net locations) have been identified within the 5,500 net acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Haynesville acreage further, we believe it is possible that we may identify additional locations for future drilling. At September 30, 2011, these identified potential future drilling locations in the Haynesville shale play included 95 gross and 15 net locations to which we have assigned proved undeveloped reserves.

We also have a large unevaluated acreage position in southwest Wyoming and adjacent areas in Utah and Idaho where we began drilling our initial well in February 2011 to test the Meade Peak natural gas shale. We reached a depth of 8,200 feet, approximately 300 feet above the top of the Meade Peak shale, before having operations suspended for several months due to wildlife restrictions. We resumed operations on this initial test well in September 2011 and completed drilling and coring operations on this well in November 2011. In addition, we have leasehold interests in the Delaware and Midland Basins in southeast New Mexico and west Texas where we are developing new oil and natural gas prospects.

We are active both as an operator and as a co-working interest owner with larger industry participants including affiliates of Chesapeake Energy Corporation, EOG Resources, Inc., Royal Dutch Shell plc and others. Of the 213 gross wells we have drilled or participated in drilling, we drilled approximately half of these wells as the operator. At September 30, 2011, we were the operator for approximately 80% of our Eagle Ford and 70% of our Haynesville acreage, including approximately 22% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in that core area is operated by a subsidiary of Chesapeake Energy Corporation. We also operate all of our acreage in southwest Wyoming and the adjacent areas of Utah and Idaho, as well as the vast majority of our acreage in southeast New Mexico and west Texas.

 

 

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Our net proceeds from this offering, after repaying the then outstanding borrowings under our revolving credit agreement ($123.0 million at January 27, 2012, excluding outstanding letters of credit), when taken together with our cash flows and future potential borrowings under our credit agreement, will be used to fund our 2012 capital expenditure requirements and for potential acquisitions of interests and acreage (none of which have been identified). As a result of our anticipated increases in production and reserves, we expect to have a sufficient increase in our cash flows from operations during the year ending December 31, 2012, as compared to our cash flows from operations in prior periods, as well as a sufficient increase in the borrowing base under our credit agreement to help fund our 2012 capital expenditure budget. A majority of our anticipated increase in cash flows during the year ending December 31, 2012 is expected to come from our exploration activities on unproved properties at September 30, 2011 in the Eagle Ford shale play assuming such exploration activities are successful. These anticipated increases in our cash flows from operations are based upon current oil and natural gas prices and the hedges we currently have in place. If our exploration activities result in less cash flows than anticipated, we may seek additional sources of capital, including through borrowings under our credit agreement (assuming availability under our borrowing base) or from the issuance of additional equity or debt securities. In addition, we may modify our planned capital expenditure budget for 2012 accordingly. Exploration activities are subject to a number of risks and uncertainties that could impact our ability to sufficiently increase our reserves, cash flows from operations and borrowing base under our credit agreement. See “Risk Factors — Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows From Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth” and “— Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties That Could Adversely Affect Our Business.” We anticipate that we may need to access future borrowings under our credit agreement within 30 days following completion of this offering to fund a portion of our 2012 capital expenditure requirements in excess of amounts available from our cash flows and the net proceeds of this offering. See “Use of Proceeds.”

The following table presents our 2012 anticipated capital expenditure budget of approximately $313.0 million segregated by target formations and by whether the wells are considered to be exploration or development wells.

 

    2012 Anticipated Drilling     2012 Anticipated Capital
Expenditure Budget
 
    Gross Wells(1)    

 

    Net Wells(1)     (in millions)(2)  
    Exploration     Development     Total     Exploration     Development     Total     Exploration     Development     Total  

South Texas

                 

Eagle Ford

    13.0        15.0        28.0        11.8        13.8        25.6      $ 122.3      $ 134.9      $ 257.2   

Austin Chalk

    2.0               2.0        2.0               2.0        11.3               11.3   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Area Total

    15.0        15.0        30.0        13.8        13.8        27.6        133.6        134.9        268.5   

NW Louisiana / E Texas

                 

Haynesville

    6.0        19.0        25.0        0.2        1.3        1.5        1.9        11.6        13.5   

Cotton Valley

                                                              
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Area Total

    6.0        19.0        25.0        0.2        1.3        1.5        1.9        11.6        13.5   

SW Wyoming, NE Utah, SE Idaho

    1.0               1.0        0.4               0.4        2.5               2.5 (3) 

SE New Mexico, West Texas

                                                              

Other

    N/A        N/A        N/A        N/A        N/A        N/A        25.0        3.5        28.5 (4) 
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    22.0        34.0        56.0        14.4        15.1        29.5      $ 163.0      $ 150.0      $ 313.0   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

 

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(1) Includes wells we currently expect to drill and complete as operator, plus those wells in which we currently plan to participate as a non-operator in 2012.

 

(2) Our capital expenditure budget is based on our net working interests in the properties.

 

(3) We have a carried interest for $5.0 million of the cost of this well presuming the election of our joint venture partner to participate in the drilling of this well.

 

(4) Includes $20.0 million to acquire additional leasehold interests primarily prospective for oil and liquids production in southeast New Mexico and west Texas. Also includes $6.5 million in leasehold, seismic and infrastructure expenditures for the Eagle Ford.

Although we intend to allocate a portion of our 2012 capital expenditure budget to financing exploration, development and acquisition of additional interests in the Haynesville shale play, we currently intend to allocate approximately 84% of our 2012 capital expenditure budget to the exploration, development and acquisition of additional interests in the Eagle Ford shale play. Including these anticipated capital expenditures in the Eagle Ford shale play, we plan to dedicate about 94% of our 2012 anticipated capital expenditure budget to opportunities prospective for oil and liquids production. While we have budgeted $313.0 million for 2012, the aggregate amount of capital we will expend may fluctuate materially based on market conditions and our drilling results. Since at September 30, 2011, just over 90% of our Haynesville acreage was held by production and approximately 80% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2013, we possess the financial flexibility to allocate our capital when we believe it is economical and justified.

Recent Developments

Recent Results

At January 16, 2012, we had drilled an aggregate of 11 Eagle Ford horizontal wells as operator. Seven of these wells have been completed and are producing. One of these wells, the Martin Ranch #8H in La Salle County, Texas, is currently undergoing completion operations, and we anticipate that two additional wells, the Martin Ranch #6H and the Martin Ranch #7H, will be completed in the near future. The Matador Sickenius ORCA #1H in Karnes County, Texas is also expected to be completed during the first quarter of 2012. At January 16, 2012, we had two contracted drilling rigs operating in the Eagle Ford play: one in La Salle County and the second in Karnes County.

For the month of December 2011, our daily production averaged approximately 43.4 MMcfe per day, including 39.8 MMcf of natural gas per day and 600 Bbl of oil per day. During the first 11 days of January 2012, our daily production averaged approximately 53.2 MMcfe per day, including 42.4 MMcf of natural gas per day and 1,800 Bbl of oil per day.

In December 2011, four of our Eagle Ford wells, the Martin Ranch #2H, #3H and #5H in La Salle County, Texas and the Lewton #1H in DeWitt County, Texas, began producing. In January 2012, we estimated that these four wells and six associated proved undeveloped locations increased our proved oil and natural gas reserves by approximately 2.8 million barrels of oil and 4.2 Bcf of natural gas as of December 31, 2011. These incremental estimates of proved reserves were prepared by our engineering staff and have been reviewed for their reasonableness by Netherland, Sewell & Associates, Inc., our independent reservoir engineers. These estimates were determined in accordance with guidelines established by the Securities and Exchange Commission for estimating and reporting oil and natural gas reserves. At January 16, 2012, we had not yet completed the estimates of our proved oil and natural gas reserves for the remainder of our properties at December 31, 2011.

 

 

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Other Developments

Between November 2011 and January 2012, we entered into various costless collars to mitigate our exposure to oil price volatility and enhance predictability of our cash flows in 2012 and 2013. As of January 13, 2012, we have hedged a total of 1,060,000 Bbl of oil for 2012 and a total of 780,000 Bbl of oil for 2013. For 2012, all collars have a price floor of $90.00/Bbl and price ceilings that range from $104.20/Bbl to $113.75/Bbl. For 2013, all collars have price floors of $85.00/Bbl or $90.00/Bbl and price ceilings that range from $102.25/Bbl to $110.40/Bbl. These costless collars may limit our potential gains if oil prices rise above the specified price ceilings. For additional information, see “Risk Factors—Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in Financial Losses” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Exposure.”

In December 2011, we amended and restated our senior secured revolving credit agreement. This amendment increased the maximum facility amount from $150 million to $400 million. Borrowings are limited to the lesser of $400 million or the borrowing base, which will be $100 million immediately following this offering. On January 25, 2012, we borrowed an additional $10.0 million under this agreement which brought our total borrowings to $123.0 million.

In November and December 2011, we completed three additional operated Eagle Ford horizontal wells, the Martin Ranch #2H, #3H and #5H in northeastern La Salle County, Texas. During initial flow tests on these wells, the Martin Ranch #2H tested at approximately 1,310 Bbls of oil and 1.8 MMcf of natural gas per day, the Martin Ranch #3H tested at approximately 620 Bbls of oil and 0.5 MMcf of natural gas per day, and the Martin Ranch #5H tested at approximately 810 Bbls of oil and 0.6 MMcf of natural gas per day. All three wells were turned to sales in late December 2011. We are the operator and have a 100% working interest in these three wells.

In August 2011, we completed our fourth operated Eagle Ford horizontal well, the Lewton #1H in DeWitt County, Texas. This well began producing to sales in late December 2011, and in early January 2012, the well was producing approximately 2.7 MMcf of natural gas and 600 Bbls of condensate per day. We are the operator of this well and paid 100% of the costs to drill and complete the well. We will receive 85% of the revenues attributable to the working interest in the well until we have recovered all of our acquisition, drilling and completion costs, after which time, our partner will receive 50% of the revenues attributable to the working interest in the well and we and our partner will each maintain a 50% working interest in the well.

Between March and July 2011, we acquired leasehold interests in approximately 6,300 gross and 4,800 net acres in DeWitt, Karnes, Wilson and Gonzales Counties, Texas in the Eagle Ford shale play from Orca ICI Development, JV. We believe that all of this acreage is in an oil and liquids prone area of the Eagle Ford play. We believe that the acreage in Wilson and Gonzales Counties and a portion of DeWitt County will be prospective for oil and liquids from the Austin Chalk formation in addition to the Eagle Ford. We paid approximately $31.5 million to acquire this acreage. We currently own a 50% working interest in the acreage (approximately 2,800 gross and 1,400 net acres) in DeWitt County and are the operator. We currently own a 100% working interest in the acreage (approximately 3,500 gross and 3,400 net acres) in Karnes, Wilson and Gonzales Counties and are the operator.

In March 2011, first sales of natural gas began from our Williams 17 H#1 well, located in what we believe to be the core area of the Haynesville shale play in northwest Louisiana. We began producing this

 

 

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well at a constrained rate of about 10.0 MMcf of natural gas per day. During November 2011, this well produced at an average daily rate of 4.5 MMcf of natural gas per day, and through November 30, 2011, had produced approximately 1.7 Bcf of natural gas. We are the operator and have a 100% working interest and a favorable 87.5% net revenue interest in this well.

In February 2011, we completed our third operated Eagle Ford horizontal well, the Affleck #1H, in eastern Dimmit County, Texas. This well tested at approximately 415 Bbls of oil and 5.4 MMcf of natural gas per day during an initial flow test. During November 2011, this well produced at an average daily rate of 0.9 MMcf of natural gas and 70 Bbls of oil per day. We are the operator and have a 100% working interest in this well.

In January 2011, we completed a private placement offering of 1,922,199 shares of our Class A common stock at $11.00 per share for an aggregate amount of $21,144,189.

In January 2011, we completed our second operated Eagle Ford horizontal well, the Martin Ranch #1H, in northeastern La Salle County, Texas. First sales of oil and natural gas from this well began in late March at approximately 700 Bbls of oil and 350 Mcf of natural gas per day. During November 2011, the well produced at an average daily rate of approximately 520 Bbls of oil and 0.6 MMcf of natural gas per day, and through November 30, 2011, had produced a total of approximately 111,000 Bbls of oil and 135 MMcf of natural gas. We are the operator and have a 100% working interest in this well.

In January 2011, first sales of oil and natural gas began from our first operated Eagle Ford horizontal well, the JCM Jr. Minerals #1H, in southern La Salle County, at approximately 3.4 MMcf of natural gas and 135 Bbls of condensate per day. During November 2011, the well produced at an average daily rate of approximately 0.6 MMcf of natural gas and 12 Bbls of condensate per day, and through November 30, 2011, had produced a total of approximately 416 MMcf of natural gas and 10,900 Bbls of condensate. We are the operator and have a 100% working interest in this well.

In January 2011, we completed our first horizontal Cotton Valley well, the Tigner Walker H#1-Alt., in DeSoto Parish, Louisiana. First sales of natural gas from this well began in late January at approximately 4.6 MMcf of natural gas per day. During November 2011, the well produced at an average daily rate of approximately 1.9 MMcf of natural gas per day, and through November 30, 2011, had produced a total of approximately 900 MMcf of natural gas. We are the operator and have a 100% working interest in this well subject to a reversionary interest at payout.

On December 31, 2010, first sales of natural gas began from our L.A. Wildlife H#1 Alt. horizontal well, located in what we believe to be the core area of the Haynesville shale play in northwest Louisiana. We began producing this well at a constrained rate of about 10.0 MMcf of natural gas per day. During November 2011, the well produced at an average daily rate of approximately 10.0 MMcf of natural gas per day, and through November 30, 2011, had produced a total of approximately 3.2 Bcf of natural gas. We are the operator and have a 95% working interest in this well.

 

 

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Business Strategies

Our goal is to increase shareholder value by building reserves, production and cash flows at an attractive return on invested capital. We plan to achieve our goal by executing the following strategies:

 

   

Focus Exploration and Development Activity on Our Eagle Ford and Haynesville Shale Assets.

We have established core acreage positions in the Eagle Ford and Haynesville shale plays, which we believe are two of the most active and economically viable shale plays in North America. Although we intend to allocate a portion of our 2012 capital expenditure budget to financing exploration, development and acquisition of additional interests in the Haynesville shale play, we currently intend to allocate approximately 84% of our 2012 capital expenditure budget to the exploration, development and acquisition of additional interests in the Eagle Ford shale play. Since just over 90% of our Haynesville acreage was held by production and approximately 80% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2013 at September 30, 2011, we have the flexibility to develop our acreage in a disciplined manner in order to maximize the resource recovery from these assets. We believe the economics for development in these two areas are attractive at current commodity prices.

 

   

Identify, Evaluate and Exploit Oil Plays to Create a More Balanced Portfolio.

Although most of our current proved reserves are classified as natural gas, we have been evaluating various oil plays to find and execute upon opportunities that would fit well with our exploration and operating strategies. We believe our interests in the Eagle Ford shale play will enable us to create a more balanced commodity portfolio through the drilling of locations that are prospective for oil and liquids. We believe oil and liquids opportunities represent about 94% of our anticipated 2012 capital expenditure budget. We expect to continue to create and acquire additional prospects and opportunities for the exploration and production of oil and liquids.

 

   

Pursue Opportunistic Acquisitions.

We believe our management team’s familiarity with our key operating areas and its contacts with the operators and mineral owners in those regions enable us to identify high-return opportunities at attractive prices. We actively pursue opportunities to acquire unproved and unevaluated acreage, drilling prospects and low-cost producing properties within our core areas of operations where we have operational control and can enhance value and performance. We view these acquisitions as an important component of our business strategy and intend to selectively make acquisitions on attractive terms that complement our growth and help us achieve economies of scale.

 

   

Maintain Our Financial Discipline.

As an operator, we leverage advanced technologies and integrate the knowledge, judgment and experience of our management and technical teams. We believe our team demonstrates financial discipline that is achieved by our approach to evaluating and analyzing prospects and prior drilling and completion results before allocating capital and is reflected in the improvements our team has attained on reducing unit costs. When we are not the operator, we proactively engage with the operators in an effort to ensure similar financial discipline. Additionally, we conduct our own internal geological and engineering studies on these prospects and provide input on the drilling, completion and operation of many of these non-operated wells pursuant to our

 

 

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agreements and relationships with the operators. Through these methods and practices, we believe we are well-positioned to control the expenses and timing of development and exploitation of our properties.

 

   

Maintain Proactive and Ongoing Relationships with Other Industry Participants.

We believe maintaining proactive and ongoing relationships with other industry operators and vendors enhances our understanding of the shale plays and allows us to leverage their expertise without having to commit substantial capital. We currently participate in various drilling activities with larger industry participants, including affiliates of Chesapeake Energy Corporation, EOG Resources, Inc., Royal Dutch Shell plc and others. We are also active participants in three industry shale consortia: the North American Gas Shale, Haynesville and Bossier Shale and Eagle Ford Shale consortia organized by Core Laboratories, LP. As active members in various professional societies, our staff and board members also regularly interact on a professional basis with other industry participants.

Competitive Strengths

We believe our prior success is, and our future performance will be, directly related to the following combination of strengths that will enable us to implement our strategies:

 

   

High Quality Asset Base in Attractive Areas.

We have key acreage positions in active areas of the Eagle Ford and Haynesville shale plays. We believe our assets in these plays are characterized by low geological risk and similar repeatable drilling opportunities that we expect will result in a predictable production growth profile. The commodity mix of our production and reserves is expected to become more balanced as a result of our planned activities on our Eagle Ford and Austin Chalk acreage, which is located in oil and liquids prone areas of the plays. In addition to the Haynesville shale, our east Texas and north Louisiana assets have multiple, recognized geologic horizons, including the Middle Bossier shale, Cotton Valley and Hosston (Travis Peak) formations. We also believe there is additional resource potential in our oil and natural gas prospects in southeast New Mexico and west Texas, along with our natural gas prospects in southwest Wyoming and adjacent areas in Utah and Idaho.

 

   

Large, Multi-year, Development Drilling Inventory.

Within our northwest Louisiana/east Texas and south Texas regions, we have identified 818 gross and 313 net drilling locations, including 197 gross and 157 net locations in the Eagle Ford shale play and 545 gross and 104 net locations in the Haynesville shale play. At September 30, 2011, these identified drilling locations included 2 gross and 2 net locations to which we have assigned proved undeveloped reserves in the Eagle Ford shale play and 95 gross and 15 net locations to which we have assigned proved undeveloped reserves in the Haynesville shale play. We have identified 28 gross and 26 net locations in the Eagle Ford shale play and 25 gross and 2 net locations in the Haynesville shale play that we expect to drill in 2012, the completion of which would represent approximately 14% and 5% of our identified gross drilling locations in these two areas at September 30, 2011, respectively. Additionally, we expect to identify and develop additional locations across our broad exploration portfolio as we evaluate our Cotton Valley, Austin Chalk, Meade Peak and Delaware and Midland Basin assets. We believe our multi-year, identified drilling inventory and exploration portfolio provide visible near-term growth in our production and reserves, and highlight the long-term resource potential across our asset base.

 

 

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Financial Flexibility to Fund Expansion.

Historically, we have maintained financial flexibility by obtaining capital through shareholder investments and our operational cash flows while having access to additional borrowings, which has allowed us to take advantage of acquisition opportunities as they arise. At September 30, 2011, on an as adjusted basis to give effect to this offering and our use of proceeds, we expect to have at least $98.7 million available for borrowings under our credit agreement after giving effect to outstanding letters of credit. Excluding any possible acquisitions, we expect to maintain our current financial flexibility by funding our entire 2012 capital expenditure budget through the net proceeds we receive from this offering, together with our cash flows and future potential borrowings under our credit agreement. As a result of our anticipated increases in production and reserves, we expect to have a sufficient increase in our cash flows from operations during the year ending December 31, 2012, as compared to our cash flows from operations in prior periods, as well as a sufficient increase in the borrowing base under our credit agreement to help fund our 2012 capital expenditure budget. A majority of our anticipated increase in cash flows during the year ending December 31, 2012 is expected to come from our exploration activities on unproved properties at September 30, 2011 in the Eagle Ford shale play assuming such exploration activities are successful. These anticipated increases in our cash flows from operations are based upon current oil and natural gas prices and the hedges we currently have in place. If our exploration activities result in less cash flows than anticipated, we may seek additional sources of capital, including through borrowings under our credit agreement (assuming availability under our borrowing base) or from the issuance of additional equity or debt securities. In addition, we may modify our planned capital expenditure budget for 2012 accordingly. Exploration activities are subject to a number of risks and uncertainties that could impact our ability to sufficiently increase our reserves, cash flows from operations and borrowing base under our credit agreement. See “Risk Factors — Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows From Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth” and “— Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties That Could Adversely Affect Our Business.” We anticipate that we may need to access future borrowings under our credit agreement within 30 days following completion of this offering to fund a portion of our 2012 capital expenditure requirements in excess of amounts available from our cash flows and the net proceeds of this offering. Our availability of capital as described above will also allow us to maintain our competitiveness in seeking to acquire additional oil and natural gas properties as opportunities arise. A strong balance sheet and interest savings should also reduce unit costs and increase profitability. In addition, since a large portion of our Eagle Ford and Haynesville acreage was held by production at September 30, 2011, we have the financial flexibility to allocate our capital when we believe it is economical and justified.

 

   

Experienced and Incentivized Management, Technical Team and Board.

Our management and technical teams possess extensive oil and natural gas expertise with an average of over 25 years of relevant industry experience from companies such as Matador Petroleum Corporation, S. A. Holditch & Associates, Inc., Schlumberger Limited, Conoco and ARCO, and we believe they have a demonstrated record of growth and financial discipline over many years. The management team has experience in drilling and completing hundreds of vertical

 

 

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and horizontal wells in unconventional resource plays, including the Cotton Valley, Bossier, Wilcox/Vicksburg, Austin Chalk, Haynesville and Eagle Ford plays. Our management team’s experience is complemented by a strong technical team with deep knowledge of advanced geophysical, drilling and completion technologies whose members are active in their professional societies. Additionally, we have a group of board members and special advisors with considerable experience and expertise in the oil and natural gas industry and in managing other successful enterprises who provide insight and perspective regarding our business and the evaluation, exploration, engineering and development of our prospects. In addition to its considerable experience, our management team currently owns and will continue to own a significant direct ownership interest in us immediately following the completion of this offering. We believe our management team’s direct ownership interest, as well as its ability to increase its holdings over time through our long-term incentive plan, aligns management’s interests with those of our shareholders.

 

   

Extensive Geologic, Engineering and Operational Experience in Unconventional Reservoir Plays.

The individuals on our technical team are highly experienced in analyzing unconventional reservoir plays and in horizontal drilling, completion and production operations in a number of geographic areas. Our geologists have extensive experience in analyzing unconventional reservoir plays throughout the United States, including our principal areas of interest, by using the latest imaging technology, such as 2-D and 3-D seismic interpretation, and petrophysical analysis. In addition, our technical team has been directly involved in over 26 different horizontal well drilling and/or operations programs in both onshore and offshore formations located in the United States and abroad. Our team’s diverse and broad horizontal drilling experience includes most, if not all, techniques used in modern day drilling. Additionally, our team has in-depth experience with various horizontal completion techniques and their applications in multiple unconventional plays. We intend to leverage our team’s geological expertise and horizontal drilling and completion experience to develop and exploit our large, multi-year development drilling inventory.

 

   

Multi-Disciplined Approach to New Opportunities.

Our process for evaluating and developing new oil and natural gas prospects is a result of what we believe is an organizational philosophy that is dedicated to a systematic, multi-disciplinary approach to new opportunities with an emphasis on incorporating petroleum systems, geosciences, technology and finance into the decision-making process. We recognize the importance of consulting multiple individuals in our organization across all disciplines and all levels of responsibility prior to making exploration, acquisition or development decisions and the formulation of key criteria for successful exploration and development projects in any given play to enhance our decision-making. We also conduct a post-completion review of our major decisions to determine what we did right and where we need to improve. At times, this approach results in a decision to accelerate our drilling program or expand our positions in certain areas. Other times, this approach results in a decision to mitigate risk associated with our exploration and development programs by sharing operational risks and costs with other industry participants or exiting an area altogether. We believe this multi-disciplined approach underpins our track record of value creation and represents the best way to deliver consistent, year-over-year results to our shareholders.

 

 

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Certain Risk Factors

An investment in our common stock involves risks that include the speculative nature of oil and natural gas exploration and production, competition, volatile oil and natural gas prices and other material factors. In particular, the following considerations may offset our competitive strengths or have a negative effect on both our business strategy as well as on activities on our properties, which could cause a decrease in the price of our common stock and result in a loss of all or a portion of your investment:

 

   

Our success is dependent on the prices of oil and natural gas. Low oil or natural gas prices or the substantial volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations;

 

   

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition, results of operations and cash flows;

 

   

Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will receive, and significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves;

 

   

Our exploration, development and exploitation projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth;

 

   

The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our financial condition, results of operations and cash flows;

 

   

Because our reserves and production are concentrated in a small number of properties, problems in production and markets relating to any property could have a material impact on our business;

 

   

Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities;

 

   

We may have accidents, equipment failures or mechanical problems while drilling or completing wells or in production activities, which could adversely affect our business;

 

   

We have limited control over activities on properties we do not operate;

 

   

Approximately 67% of our total proved reserves at September 30, 2011 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced;

 

   

Our success depends, to a large extent, on our ability to retain our key personnel, including our Chairman of the Board, Chief Executive Officer and President, the members of our board of directors and our special board advisors, and the loss of any key personnel, board member or special board advisor could disrupt our business operations; and

 

   

If any of the material weaknesses previously identified by our independent registered public accountants persist or if we fail to establish and maintain effective internal control over financial reporting in the future, our ability to accurately report our financial results could be adversely affected.

 

 

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For a discussion of these risks and other considerations that could negatively affect us, including risks related to this offering and our common stock, see “Risk Factors” beginning on page 23 and “Cautionary Note Regarding Forward-Looking Statements.”

Organizational Structure

Matador Resources Company was formed as a Texas corporation in July 2003. Pursuant to the terms of the corporate reorganization that was completed on August 9, 2011, former Matador Resources Company, now known as MRC Energy Company, became a wholly owned subsidiary of current Matador Resources Company, formerly known as Matador Holdco, Inc. In connection with the reorganization, former Matador Resources Company changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its corporate name to Matador Resources Company.

The following diagram indicates our ownership structure and organizational structure after giving effect to our corporate reorganization and this offering. The shareholder ownership information set forth below is based on the beneficial ownership of our common stock after consummation of this offering based on the number of shares beneficially owned by our current shareholders at January 27, 2012.

 

LOGO

 

 

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Corporate Information

We are headquartered in Dallas, Texas. Our executive offices and mailing address are at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. Our telephone number is (972) 371-5200. We expect to have an operational website that meets Securities and Exchange Commission, or SEC, and New York Stock Exchange, or NYSE, requirements concurrently with, or prior to, the completion of this offering. Information on our website or any other website is not and will not be incorporated by reference herein and does not and will not constitute a part of this prospectus.

 

 

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The Offering

 

Issuer

   Matador Resources Company

Selling shareholders

   See “Principal and Selling Shareholders.”

Common stock offered by us

   11,666,667 shares (12,366,667 shares if the underwriters’ over-allotment is exercised in full)

Common stock offered by selling shareholders

   1,666,667 shares (2,966,667 shares if the underwriters’ over-allotment is exercised in full)

Common stock outstanding after offering

  

54,719,860 shares (55,419,860 shares if the underwriters’ over-allotment is exercised in full)

 

The number of shares to be outstanding after this offering is based on 43,053,193 shares of our common stock outstanding at January 16, 2012. This number excludes 4,000,000 additional shares that are authorized for future issuance under our equity incentive plan and 739,500 additional shares that may be issued subsequent to the offering pursuant to outstanding stock options.

Over-allotment option

   We and the selling shareholders have granted the underwriters a 30-day option to purchase up to an aggregate of 700,000 and 1,300,000 additional shares of our common stock, respectively, to cover any over-allotments.

Use of proceeds

  

We estimate that our net proceeds from this offering will be approximately $127.6 million, or $135.4 million if the underwriters exercise their over-allotment option in full, in each case after deducting the underwriting discounts and commissions and estimated offering expenses.

 

We intend to use the net proceeds we receive from this offering to repay the then outstanding borrowings under our credit agreement ($123.0 million outstanding at January 27, 2012, excluding outstanding letters of credit). The remaining net proceeds will be used to fund a portion of our anticipated 2012 capital expenditure budget. We will not receive any of the proceeds from the sale of shares of our common stock by the selling shareholders. See “Use of Proceeds.”

 

Affiliates of certain of the underwriters are lenders under our senior secured revolving credit agreement and, accordingly, will receive more than 5% of the proceeds from this offering. See “Use of Proceeds” and “Underwriters — Conflicts of Interest.”

 

 

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Dividend policy

   We do not anticipate paying any cash dividends on our common stock.

Risk factors

   You should carefully read and consider the information beginning on page 23 of this prospectus set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our common stock.

New York Stock Exchange Symbol

 

  

MTDR

 

 

 

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Summary Financial, Reserves and Operating Data

You should read the following summary financial, reserves and operating data in conjunction with “Selected Historical Consolidated and Other Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business” and our audited and unaudited historical consolidated financial statements and related notes thereto included elsewhere in this prospectus. The financial information included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.

Financial Data

The following tables set forth summary historical consolidated financial information for the company and its subsidiaries. The historical consolidated financial information is derived from the audited consolidated financial statements for the company and its subsidiaries at and for the years ended December 31, 2010, 2009 and 2008 and the unaudited condensed consolidated financial statements for the company and its subsidiaries at and for the nine months ended September 30, 2011 and 2010. The balance sheet data has also been adjusted to reflect the estimated net proceeds to be received by us from this offering. The audited consolidated financial statements for the company and its subsidiaries at and for the years ended December 31, 2010, 2009 and 2008 and the unaudited condensed consolidated financial statements for the company and its subsidiaries at and for the nine months ended September 30, 2011 and 2010 are contained elsewhere in this prospectus. Our consolidated financial statements for the years ended December 31, 2010, 2009 and 2008 were audited by Grant Thornton LLP.

 

     Year Ended December 31,     Nine Months Ended
September 30,
 
     2010     2009     2008     2011     2010  
                       

(Unaudited)

   

(Unaudited)

 
(In thousands, except per share data)       

Statement of operations data:

          

Revenues:

          

Oil and natural gas revenues

   $ 34,042      $ 19,039      $ 30,645      $ 52,009      $ 25,182   

Realized gain (loss) on derivatives

     5,299        7,625        (1,326     4,237        2,988   

Unrealized gain (loss) on derivatives

     3,139        (2,375     3,592        1,534        5,813   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     42,480        24,289        32,911        57,780        33,983   

Expenses:

          

Production taxes and marketing

     1,982        1,077        1,639        4,801        1,235   

Lease operating

     5,284        4,725        4,667        5,639        3,801   

Depletion, depreciation and amortization

     15,596        10,743        12,127        22,578        10,931   

Accretion of asset retirement obligations

     155        137        92        158        107   

Full-cost ceiling impairment

            25,244        22,195        35,673          

General and administrative

     9,702        7,115        8,252        9,395        6,793   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

     32,719        49,041        48,972        78,244        22,867   

Operating income (loss)

     9,761        (24,752     (16,061     (20,464     11,116   

Other:

          

Other (expense) income

     137        402        139,962 (1)      (213     300   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

     9,898        (24,350     123,901        (20,677     11,416   

Net income (loss)

   $ 6,377      $ (14,425   $ 103,878      $ (13,725   $ 7,373   

 

 

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     Year Ended December 31,      Nine Months Ended
September 30,
 
     2010      2009     2008      2011     2010  
                         

(Unaudited)

   

(Unaudited)

 
(In thousands, except per share data)  

Earnings (loss) per share (basic) (2)

            

Class A

   $ 0.15       $ (0.37   $ 2.50       $ (0.33   $ 0.18   

Class B(2)

   $ 0.42       $ (0.10   $ 2.77       $ (0.13   $ 0.38   

Weighted average common shares outstanding (basic)

     41,037         40,123        41,385         42,702        40,880   

Class A

     40,007         39,093        40,355         41,671        39,849   

Class B(2)

     1,031         1,031        1,031         1,031        1,031   

 

(1) Increase in other income was primarily due to gain on unproved and unevaluated property dispositions in 2008.

 

(2) At September 30, 2011, we had 1,030,700 shares of Class B common stock issued and outstanding. All shares of Class B common stock will automatically convert on a one-for-one basis into shares of Class A common stock upon the consummation of this offering pursuant to the terms of our certificate of formation. If the Class B common stock were converted at the applicable date, the earnings per share would not be materially different than the Class A earnings per share.

 

     At December 31,     At September 30,  
     2010      2009      2008     2011     2010  
                         Actual     As
Adjusted(1)
       
(In thousands)                       

(Unaudited)

   

(Unaudited)

   

(Unaudited)

 

Balance sheet data:

              

Cash and cash equivalents

   $ 21,060       $ 104,230       $ 150,768      $ 7,768      $ 14,883      $ 38,618   

Certificates of deposit

     2,349         15,675         20,782        2,085        2,085        7,429   

Net property and equipment

     303,880         142,078         125,261        350,279        388,279        227,052   

Total assets

     346,382         277,400         314,539        383,244        428,359        291,423   

Current liabilities

     30,097         8,868         35,475        50,102        25,102        19,396   

Long term liabilities

     34,408         4,210         2,059        64,604        4,604        8,125   

Total shareholders’ equity

   $ 281,877       $ 264,321       $ 277,005      $ 268,538      $ 398,653      $ 263,902   

 

(1) As adjusted to give effect to (a) this offering (assuming aggregate net proceeds of $127.6 million are received by us), (b) the application of the net proceeds to be received by us to repay the then outstanding borrowings under our credit agreement ($123.0 million less outstanding letters of credit), (c) $38.0 million being added to property and equipment reflecting the use of $38.0 million in additional borrowings under our credit agreement between September 30, 2011 and January 27, 2012, (d) the balance of the net proceeds from this offering being added to cash and cash equivalents to fund a portion of our 2012 capital expenditure budget and (e) the proceeds to be received by us as a result of the issuance of 285,000 shares of common stock to certain holders of stock options prior to the consummation of this offering in connection with the exercise of their stock options at an exercise price of $9.00 per share.

 

     Year Ended December 31,     Nine Months Ended
September 30,
 
     2010     2009     2008     2011     2010  
(In thousands)                     

(Unaudited)

   

(Unaudited)

 

Other financial data:

          

Net cash provided by operating activities

   $ 27,273      $ 1,791      $ 25,851      $ 34,443      $ 21,390   

Net cash (used in) provided by investing activities

     (147,334     (49,415     115,481        (107,772     (78,718

Oil and natural gas properties capital expenditures

     (159,050     (54,244     (104,119     (104,733     (86,031

Expenditures for other property and equipment

     (1,610     (307     (3,012     (3,303     (934

Net cash provided by (used in) financing activities

     36,891        1,086        419        60,037        (8,284

Adjusted EBITDA(1)

   $ 23,635      $ 15,184      $ 18,411      $ 37,550      $ 17,133   

 

(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “— Non-GAAP Financial Measures” below.

Non-GAAP Financial Measures

We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, property impairments, unrealized derivative gains and losses, non-recurring

 

 

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income and expenses and non-cash stock-based compensation expense, including stock option and grant expense and restricted stock grants. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. “GAAP” means Generally Accepted Accounting Principles.

Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents our calculation of Adjusted EBITDA and reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively.

 

     Year Ended December 31,     Nine Months
Ended
September 30,
 
     2010     2009     2008     2011     2010  
(In thousands)       

Unaudited Adjusted EBITDA reconciliation to Net Income (Loss):

          

Net income (loss)

   $ 6,377      $ (14,425   $ 103,878      $ (13,725   $ 7,373   

Interest expense

     3                      461          

Total income tax provision (benefit)

     3,521        (9,925     20,023        (6,952     4,043   

Depletion, depreciation and amortization

     15,596        10,743        12,127        22,578        10,931   

Accretion of asset retirement obligations

     155        137        92        158        107   

Full-cost ceiling impairment

            25,244        22,195        35,673          

Unrealized (gain) loss on derivatives

     (3,139     2,375        (3,592     (1,534     (5,812

Stock option and grant expense

     824        622        605        855        466   

Restricted stock grants

     74        34        60        36        25   

Net (gain)/loss on asset sales and inventory impairment

     224        379        (136,977              
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 23,635      $ 15,184      $ 18,411      $ 37,550      $ 17,133   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
     Year Ended December 31,     Nine Months
Ended
September 30,
 
     2010     2009     2008     2011     2010  
(In thousands)       

Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities:

          

Net cash provided by operating activities

   $ 27,273      $ 1,791      $ 25,851      $ 34,443      $ 21,390   

Net change in operating assets and liabilities

     (2,230     15,717        (17,888     2,692        (2,846

Interest expense

     3                      461          

Current income tax (benefit) provision

     (1,411     (2,324     10,448        (46     (1,411
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 23,635      $ 15,184      $ 18,411      $ 37,550      $ 17,133   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

 

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Reserves Data

The following table presents summary data with respect to our estimated net proved oil and natural gas reserves at the dates indicated. The reserves estimates at December 31, 2008 presented in the table below are based on evaluations prepared by our engineering staff, which have been audited by LaRoche Petroleum Consultants, Ltd., independent reservoir engineers. The reserves estimates at December 31, 2010 and 2009 and at September 30, 2011 are based on evaluations prepared by our engineering staff, which have been audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with the Securities and Exchange Commission’s rules regarding oil and natural gas reserves reporting that were in effect at the time of the preparation of the reserves report. Our total estimated proved reserves are estimated using a conversion ratio of one Bbl per six Mcf.

 

     At December 31,     At September 30,  
     2010     2009     2008     2011  

Estimated proved reserves:(1) (2)

        

Natural gas (Bcf)

     127.4        63.9        19.2        155.3   

Oil (MBbls)

     152        103        131        1,083   

Total (Bcfe)

     128.3        64.5        20.0        161.8   

Developed proved reserves (Bcfe)

     44.1        26.0        20.0        55.8   

Percent developed

     34.3     40.3     100.0     34.5

Undeveloped proved reserves (Bcfe)

     84.3        38.6               106.0   

PV-10 (in thousands)(3)

   $ 119,869      $ 70,359      $ 44,069      $ 155,217   

Standardized Measure (in thousands)(4)

   $ 111,077      $ 65,061      $ 43,254      $ 143,372   

 

(1) Numbers in table may not total due to rounding.

 

(2) Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The index prices were $41.00 per Bbl for oil and $5.710 per MMBtu for natural gas at December 31, 2008. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2009 were $57.65 per Bbl for oil and $3.866 per MMBtu for natural gas, for the 12 months ended December 31, 2010 were $75.96 per Bbl for oil and $4.376 per MMBtu for natural gas, and for the 12-month period from October 2010 to September 2011 were $91.00 per Bbl for oil and $4.158 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead.

 

(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2008, 2009 and 2010 and at September 30, 2011 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2008, 2009 and 2010 and at September 30, 2011 were, in thousands, $815, $5,298, $8,792 and $11,845, respectively.

 

(4) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.

 

 

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Unaudited Operating Data

The following table sets forth summary unaudited production results for the company and its  subsidiaries for the years ended December 31, 2010, 2009 and 2008 and for the nine month periods ended  September 30, 2011 and 2010.

 

     Year Ended December 31,      Nine Months Ended
September 30,
 
       2010          2009          2008        2011         2010  

Production:

              

Natural gas (Bcf)

     8.4         4.8         3.1         10.9         5.9   

Oil (MBbls)

     33         30         37         113         24   

Total natural gas equivalents (Bcfe)(1)

     8.6         5.0         3.3         11.6         6.0   

Average net daily production (MMcfe)

     23.6         13.7         9.0         42.5         22.0   

Average sales price (per Mcfe):

              

Average sales price (including effects of hedging)

   $ 4.58       $ 5.33       $ 8.86       $ 4.85       $ 4.68   

Average sales price (before effects of hedging)

   $ 3.96       $ 3.81       $ 9.27       $ 4.48       $ 4.19   

Operating expenses (per Mcfe):

              

Production taxes and marketing

   $ 0.23       $ 0.22       $ 0.50       $ 0.41       $ 0.21   

Lease operating

   $ 0.61       $ 0.94       $ 1.41       $ 0.49       $ 0.63   

Depletion, depreciation and amortization

   $ 1.81       $ 2.15       $ 3.67       $ 1.95       $ 1.82   

General and administrative

   $ 1.13       $ 1.42       $ 2.50       $ 0.81       $ 1.13   

 

  (1) Estimated using a conversion ratio of one Bbl per six Mcf.

 

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RISK FACTORS

You should carefully consider the risks described below before making an investment decision. Our business, financial condition or results of operations could be materially adversely affected by any of these risks. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to the Oil and Natural Gas Industry and Our Business

Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.

The prices we receive for our oil and natural gas heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include the following:

 

   

the domestic and foreign supply of oil and natural gas;

 

   

the domestic and foreign demand for oil and natural gas;

 

   

the prices and availability of competitors’ supplies of oil and natural gas;

 

   

the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls;

 

   

the price and quantity of foreign imports;

 

   

the impact of U.S. dollar exchange rates on oil and natural gas prices;

 

   

domestic and foreign governmental regulations and taxes;

 

   

speculative trading of oil and natural gas futures contracts;

 

   

the availability, proximity and capacity of gathering and transportation systems for natural gas;

 

   

the availability of refining capacity;

 

   

the prices and availability of alternative fuel sources;

 

   

weather conditions and natural disasters;

 

   

political conditions in or affecting oil and natural gas producing regions, including the Middle East and South America;

 

   

the continued threat of terrorism and the impact of military action and civil unrest;

 

   

public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;

 

   

the level of global oil and natural gas inventories and exploration and production activity;

 

   

the impact of energy conservation efforts;

 

   

technological advances affecting energy consumption; and

 

   

overall worldwide economic conditions.

 

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Because we expect to produce more natural gas than oil in the immediate future, we will face more risk associated with fluctuations in the price of natural gas than oil. Approximately 98% of our production during the year ended December 31, 2010, 94% of our production during the nine month period ended September 30, 2011 and 96% of our proved reserves at September 30, 2011 are attributable to natural gas. In addition, three of our largest prospects, our Haynesville shale, Cotton Valley properties and our Meade Peak shale, currently produce or are expected to produce predominantly natural gas. As a result, they are sensitive to fluctuations in natural gas prices.

One of our current business strategies is to focus on increasing our oil and liquids production. Specifically, our near-term drilling opportunities in the Eagle Ford shale play focus on oil and liquids. We currently intend to allocate approximately 84% of our 2012 capital expenditure budget to the exploration of the Eagle Ford shale. We believe that almost 85% of our Eagle Ford acreage is prospective predominantly for oil and liquids production, and we have identified 197 gross locations for potential future drilling in our Eagle Ford acreage. Therefore, our Eagle Ford shale play is highly susceptible to changes in oil prices.

Declines in oil or natural gas prices would not only reduce our revenue, but could reduce the amount of oil and natural gas that we can produce economically. Should natural gas or oil prices decrease from current levels and remain there for an extended period of time, we may elect in the future to delay some of our exploration and development plans for our prospects, or to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities, each of which would have a material adverse effect on our business, financial condition, results of operations and reserves.

Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties That Could Adversely Affect Our Business.

Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from a location that is ready to drill to a location that will require substantial additional interpretation before it can be drilled. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during the drilling and operating processes. Before a well is spud, we may incur significant geological and geophysical (seismic) costs, which are incurred whether a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly.

If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties

 

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while drilling or completing the well, resulting in a reduction in production and reserves from the well or abandonment of the well. Whether a well is ultimately productive and profitable depends on a number of additional factors, including the following:

 

   

general economic and industry conditions, including the prices received for oil and natural gas;

 

   

shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel;

 

   

potential drainage by operators on adjacent properties;

 

   

loss of or damage to oilfield development and service tools;

 

   

problems with title to the underlying properties;

 

   

increases in severance taxes;

 

   

adverse weather conditions that delay drilling activities or cause producing wells to be shut down;

 

   

domestic and foreign governmental regulations; and

 

   

proximity to and capacity of transportation facilities.

If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected.

We May Have Accidents, Equipment Failures or Mechanical Problems While Drilling or Completing Wells or in Production Activities, Which Could Adversely Affect Our Business.

While we are drilling and completing wells or involved in production activities, we may have accidents or experience equipment failures or mechanical problems in a well that cause us to be unable to drill and complete the well or to continue to produce the well according to our plans. We may also damage a potentially hydrocarbon-bearing formation during drilling and completion operations. Such incidents may result in a reduction of our production and reserves from the well or in abandonment of the well.

Because Our Reserves and Production Are Concentrated in a Small Number of Properties, Problems in Production and Markets Relating to Any Property Could Have a Material Impact on Our Business.

Almost all of our current oil and natural gas production and our proved reserves are attributable to properties in north Louisiana and east Texas, and we expect that most of our operations in the near future will be primarily in south Texas. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled maintenance. In particular, our operations in south Texas may be adversely affected by hurricanes and tropical storms resulting in delays in exploration and drilling, damage to facilities and equipment and the inability to receive equipment or to access personnel and products at affected job sites in a timely manner. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition, results of operations and cash flows.

 

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Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline, Which Would Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.

The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent on our success in: (i) efficiently developing and exploiting our current reserves on properties owned by us or by other persons or entities and (ii) economically finding or acquiring additional oil and natural gas producing properties. In the future, we may have difficulty expanding our current production or acquiring new properties. During periods of low oil and/or natural gas prices, it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected.

Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Receive, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves.

The process of estimating accumulations of oil and natural gas is complex and is not exact, due to numerous inherent uncertainties. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of:

 

   

the quality and quantity of available data;

 

   

the interpretation of that data;

 

   

the judgment of the persons preparing the estimate; and

 

   

the accuracy of the assumptions.

The accuracy of any estimates of proved reserves generally increases with the length of the production history. Due to the limited production history of many of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data is available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance to our estimates could materially affect the quantities and present value of our reserves.

The Calculated Present Value of Future Net Revenues from Our Proven Reserves Will Not Necessarily Be the Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves.

It should not be assumed that the present value of future net cash flows included in this prospectus is the current market value of our estimated proved oil and natural gas reserves. We generally base the estimated discounted future net cash flows from proved reserves on current costs held constant over time without

 

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escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as:

 

   

actual prices we receive for oil and natural gas;

 

   

actual cost and timing of development and production expenditures;

 

   

the amount and timing of actual production; and

 

   

changes in governmental regulations or taxation.

In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under GAAP is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general.

Approximately 67% of Our Total Proved Reserves at September 30, 2011 Consisted of Undeveloped and Developed Non-Producing Reserves, and Those Reserves May Not Ultimately Be Developed or Produced.

At September 30, 2011, approximately 66% of our total proved reserves were undeveloped and approximately 1% were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced, or such reserves may not be developed or produced within the time periods we have projected or, at the costs we have budgeted. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical. In addition, delays in the development of reserves or declines in oil and/or natural gas prices in the future could cause us to have to reclassify our proved reserves as unproved reserves, which would materially affect our business, financial condition, results of operations and ability to raise capital.

Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows From Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth.

Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. The net proceeds we receive from this offering, our operating cash flows and future potential borrowings under our credit agreement or otherwise may not be adequate to fund our future acquisitions or future capital expenditure requirements. The rate of our future growth may be dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable.

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

 

   

our estimated proved oil and natural gas reserves;

 

   

the amount of oil and natural gas we produce from existing wells;

 

   

the prices at which we sell our production;

 

   

the costs of developing and producing our oil and natural gas reserves;

 

   

our ability to acquire, locate and produce new reserves;

 

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the ability and willingness of banks to lend to us; and

 

   

our ability to access the equity and debt capital markets.

In addition, future events, such as terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets have caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future.

If our revenues decrease as a result of lower oil and gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in additional exploration opportunities. Alternatively, a significant improvement in oil and gas prices could result in an increase in our capital expenditures and we may be required to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise to meet any increase in capital needs. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and future results of operations could be adversely affected.

Our Operations Are Subject to Operational Hazards and Unforeseen Interruptions for Which We May Not Be Adequately Insured.

There are numerous operational hazards inherent in oil and natural gas exploration, development, production and gathering, including:

 

   

unusual or unexpected geologic formations;

 

   

natural disasters;

 

   

adverse weather conditions;

 

   

unanticipated pressures;

 

   

loss of drilling fluid circulation;

 

   

blowouts where oil or natural gas flows uncontrolled at a wellhead;

 

   

cratering or collapse of the formation;

 

   

pipe or cement leaks, failures or casing collapses;

 

   

fires or explosions;

 

   

releases of hazardous substances or other waste materials that cause environmental damage;

 

   

pressures or irregularities in formations; and

 

   

equipment failures or accidents;

In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices.

 

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Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.

Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows.

The 2-D and 3-D Seismic Data and Other Advanced Technologies We Use Cannot Eliminate Exploration Risk, Which Could Limit Our Ability to Replace and Grow Our Reserves and Materially and Adversely Affect Our Future Cash Flows and Results of Operations.

We intend to employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Poor results from our exploration activities could limit our ability to replace and grow reserves and materially and adversely affect our future cash flows and results of operations.

We Currently Own Only a Limited Amount of Seismic and Other Geological Data and May Have Difficulty Obtaining Additional Data at a Reasonable Cost, Which Could Adversely Affect Our Future Cash Flows and Results of Operations.

We currently own only a limited amount of seismic and other geological data to assist us in exploration and development activities. We intend to obtain access to additional data in our areas of interest through licensing arrangements with companies that own or have access to that data or by paying to obtain that data directly. Seismic and geological data can be expensive to license or obtain. We may not be able to license or obtain such data at an acceptable cost.

The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.

Shortages or the high cost of drilling rigs, completion equipment and services, supplies or personnel could delay or adversely affect our operations. When drilling activity in the United States increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies

 

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and personnel and the services and products of other vendors to the industry. These costs may increase, and necessary equipment and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our financial condition, results of operations and cash flows.

In addition, the demand for hydraulic fracturing services currently exceeds the availability of fracturing equipment and crews across the industry and in our operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages has further amplified this equipment and crew shortage. If demand for fracturing services continues to increase or the supply of fracturing equipment and crews decreases, then higher costs could result and could adversely affect our business and results of operations.

Our Identified Drilling Locations Are Scheduled Out over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.

Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including the availability of equipment and capital, approval by regulators, seasonal conditions, oil and natural gas prices, assessment of risks, costs and drilling results. The final determination on whether to drill any of these locations will be dependent upon the factors described elsewhere in this prospectus as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe or at all or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our financial condition, results of operations and cash flows.

We Have Limited Control over Activities on Properties We Do Not Operate.

We are not the operator on some of our properties, particularly in the Haynesville shale. As a result of our sale of certain assets to a subsidiary of Chesapeake Energy Corporation in 2008, we do not operate one of our most significant natural gas assets in the Haynesville shale. We also acquired other non-operated acreage positions in north Louisiana. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs or control the risks could materially and adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including:

 

   

timing and amount of capital expenditures;

 

   

the operator’s expertise and financial resources;

 

   

the rate of production of reserves, if any;

 

   

approval of other participants in drilling wells; and

 

   

selection of technology.

 

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In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying natural gas reserves.

A Component of Our Growth May Come Through Acquisitions, and Our Failure to Identify or Complete Future Acquisitions Successfully Could Reduce Our Earnings and Hamper Our Growth.

We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The completion and pursuit of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations, financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential. Our financial position, results of operations and cash flows may fluctuate significantly from period to period, as a result of the completion of significant acquisitions during particular periods. If we are not successful in identifying or acquiring any material property interests, our earnings could be reduced and our growth could be restricted.

We may engage in bidding and negotiating to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise. Our credit agreement includes covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas.

We May Purchase Oil and Natural Gas Properties with Liabilities or Risks That We Did Not Know About or That We Did Not Assess Correctly, and, as a Result, We Could Be Subject to Liabilities That Could Adversely Affect Our Results of Operations.

Before acquiring oil and natural gas properties, we estimate the reserves, future oil and natural gas prices, operating costs, potential environmental liabilities and other factors relating to the properties. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not generally perform inspections on every well or property, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities.

 

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Strategic Relationships Upon Which We May Rely Are Subject to Change, Which May Diminish Our Ability to Conduct Our Operations.

Our ability to explore, develop and produce oil and natural gas resources successfully and acquire oil and natural gas interests and acreage depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These realities are subject to change and may impair our ability to grow.

To develop our business, we will endeavor to use the business relationships of our management, board and special board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies, including those that supply equipment and other resources that we expect to use in our business. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

The Marketability of Our Production Is Dependent Upon Oil and Natural Gas Gathering and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.

The unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay production from our wells. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for, and supply of, oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain these services on acceptable terms could materially harm our business. We may be required to shut-in wells for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut-in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases.

The disruption of third party facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. The third parties control when or if such facilities are restored and what prices will be charged. We generally do not purchase firm transportation on third party facilities, and, therefore, our production transportation can be interrupted by those having firm arrangements. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in Financial Losses.

To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars,” with respect to a portion of our future production. A costless collar provides us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, this arrangement is

 

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initially “costless” to us. The goal of these and other hedges is to lock in a range of prices so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil or natural gas prices rise above the maximum price established by the call option and may offer protection if prices fall below the minimum price established by the put option only to the extent of the volumes then hedged.

In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option contracts fail to perform under the contracts.

Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions.

Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil and gas prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful. Our existing oil and natural gas hedges will expire at various times during 2012 and 2013.

An Increase in the Differential Between the NYMEX or other Benchmark Prices of Oil and Natural Gas and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.

The prices that we receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark price and the prices we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. We do not have, and may not have in the future, any derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be exposed to any increase in such differentials.

We Are Subject to Government Regulation and Liability, including Complex Environmental Laws, Which Could Require Significant Expenditures.

The exploration, development, production and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation or environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. These expenditures could include payments for:

 

   

personal injuries;

 

   

property damage;

 

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containment and clean up of oil and other spills;

 

   

the management and disposal of hazardous materials;

 

   

remediation and clean-up costs; and

 

   

other environmental damages.

We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or the owners of properties adjacent to or in close proximity to those properties, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations.

We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.

The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. In the past, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. Many states have raised state taxes on energy sources, and additional increases may occur. Changes to tax laws that are applicable to us could adversely affect our business and our financial results.

Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain United States production activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. These changes were included in the White House budget proposals, released on February 26, 2009, February 1, 2010 and February 14, 2011, and may be raised again in the future. The American Jobs Act of 2011 proposed by President Obama also contains similar changes. 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 proposals 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 natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows.

 

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We May Be Required to Write Down the Carrying Value of Our Proved Properties Under Accounting Rules and these Write-Downs Could Adversely Affect Our Financial Condition.

There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low. In addition, non-cash write-downs may occur if we have:

 

   

downward adjustments to our estimated proved reserves;

 

   

increases in our estimates of development costs; or

 

   

deterioration in our exploration results.

We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is based on the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does not affect net cash flows from operating activities, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity and could lower the value of our common stock.

We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.

If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless. In such an instance, the amount paid for such oil and natural gas lease as well as any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost.

It is our practice, in acquiring oil and natural gas leases, or undivided interests in oil and natural gas leases, not to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, we will rely upon the judgment of oil and natural gas lease brokers and/or landmen who perform the field work in examining records in the appropriate governmental office before attempting to acquire a lease on a specific mineral interest.

Prior to the drilling of an oil and natural gas well, however, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil and natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may adversely impact our ability in the future to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss which could adversely affect our financial condition, results of operations and cash flows.

 

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The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business.

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things, sets forth the new framework for regulating certain derivative products including the commodity hedges of the type used by us, but many aspects of this law are subject to further rulemaking and will take effect over several years. As a result, it is difficult to anticipate the overall impact of the Dodd-Frank Act on our ability or willingness to continue entering into and maintaining such commodity hedges and the terms thereof. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future.

If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our future ability to conduct acquisitions.

Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.

Congress has considered, but has not yet passed, legislation to amend the federal Safe Drinking Water Act to remove the exemption from restrictions on underground injection of fluids near drinking water sources granted to hydraulic fracturing operations and require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand or other propping agents and chemicals under pressure into rock formations to stimulate natural gas production. We routinely use hydraulic fracturing to produce commercial quantities of oil, liquids and natural gas from shale formations such as the Haynesville and the Eagle Ford shales, where we focus our operations. Sponsors of bills before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Such legislation, if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could, and in all likelihood would, result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing operations and increasing our costs of compliance. Moreover, the U.S. Environmental Protection Agency, or EPA, is conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water and groundwater. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution of a natural gas field in Wyoming, although this study remains subject to review and public comments. Consequently, even if federal legislation is not adopted soon or at all, the performance of the hydraulic fracturing study by the EPA could spur further action at a later date towards federal legislation and regulation of hydraulic fracturing or similar production operations.

In addition, a number of states are considering or have implemented more stringent regulatory requirements applicable to fracturing, which could include a moratorium on drilling and effectively prohibit further production of natural gas through the use of hydraulic fracturing or similar operations. For example,

 

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Texas has adopted legislation that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas and the public. This legislation and any implementing regulation could increase our costs of compliance and doing business.

The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations.

Legislation or Regulations Restricting Emissions of “Greenhouse Gases” Could Result in Increased Operating Costs and Reduced Demand for the Natural Gas, Natural Gas Liquids and Oil We Produce While the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to those Effects.

On December 15, 2009, the EPA published its final findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA has adopted regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and permitting and presumably requiring a reduction in greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a final rule that expands its rule on reporting of greenhouse gas emissions to include owners and operators of petroleum and natural gas systems. Monitoring of those newly covered emissions commenced on January 1, 2011, with the first annual reports due to the EPA on March 31, 2012. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. There were attempts at comprehensive legislation establishing a cap and trade program, but that legislation appears unlikely to pass. Further, various states have adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Any such legislation could adversely affect demand for the natural gas, oil and liquids that we produce.

A Change in the Jurisdictional Characterization of Some of Our Assets by FERC or a Change in Policy by It May Result in Increased Regulation of Our Assets, Which May Cause Our Revenues to Decline and Operating Expenses to Increase.

Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission, or FERC, as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. A change in the jurisdictional characterization by FERC or Congress or a change in policy by either of them may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

 

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Should We Fail to Comply with All Applicable FERC-Administered Statutes, Rules, Regulations and Orders, We Could Be Subject to Substantial Penalties and Fines.

Under the Domenici-Barton Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation and disgorgement of profits associated with any violation. Our systems have not yet been regulated by FERC, as a natural gas company subject to the provisions of the NGA. FERC has adopted regulations that may subject certain of our otherwise non-FERC/NGA jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability.

Competition in the Oil and Natural Gas Industry is Intense Making It More Difficult for Us to Acquire Properties, Market Natural Gas and Secure Trained Personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

Our Competitors May Use Superior Technology and Data Resources that We May Be Unable to Afford or That Would Require a Costly Investment by Us in Order to Compete with Them More Effectively.

Our industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies and databases. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, many of our competitors will have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we will use or that we may implement in the future may become obsolete, and we may be adversely affected.

Certain of Our Unproved and Unevaluated Acreage Is Subject to Leases that Will Expire Over the Next Several Years Unless Production Is Established on Units Containing the Acreage.

At September 30, 2011, we had leasehold interests in approximately 122,000 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to December 31, 2013. Unless we establish production in paying quantities on units containing these leases during their terms or we renew such leases, these leases will expire. If our leases

 

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expire, we will lose our right to develop the related properties. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third party leases may have been taken and could become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows.

We May Have Difficulty Managing Growth in Our Business, Which Could Have a Material Adverse Effect on Our Business, Financial Condition, Results of Operations and Cash Flows and Our Ability to Execute Our Business Plan in a Timely Fashion.

Because of our small size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we expand our activities, including our planned increase in oil exploration, development and production, and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers and landmen could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion.

Financial Difficulties Encountered by Our Oil and Natural Gas Purchasers, Third Party Operators or Other Third Parties Could Decrease Our Cash Flow from Operations and Adversely Affect the Exploration and Development of Our Prospects and Assets.

We derive essentially all of our revenues from the sale of our oil and natural gas to unaffiliated third party purchasers, independent marketing companies and mid-stream companies. Any delays in payments from our purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations and cash flows.

Liquidity and cash flow problems encountered by our working interest co-owners or the third party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary to fund either of these contingencies or that we would be able to find a new farmout party.

We May Incur Indebtedness Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations and Our Unit Costs.

Upon the completion of this offering and the application of the net proceeds to be received by us, we expect to have available borrowings of approximately $98.7 million under our credit agreement (after giving effect to outstanding letters of credit). Our borrowing base under our credit agreement immediately following the offering will be limited to $100 million. Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future acquired oil and gas reserves. Our credit agreement is secured by substantially all of our interests in our oil and gas properties and other assets and contains covenants restricting our ability to incur additional indebtedness,

 

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which may limit our ability to obtain additional financing. In addition, the borrowing base under our credit agreement is subject to periodic redeterminations, and we could be forced to repay a portion of our borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments.

At January 27, 2012, all borrowings under our credit agreement bore interest at a variable rate of 3.25% plus a Eurodollar-based rate per annum, which equated to approximately 3.5% per annum. In the future, we may incur significant amounts of additional indebtedness, including under our credit agreement, in order to make acquisitions or to develop our properties. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly.

Our level of indebtedness could affect our operations in several ways, including the following:

 

   

a significant portion of our cash flows could be used to service our indebtedness;

 

   

a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

 

   

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

 

   

a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness may prevent us from pursuing;

 

   

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

 

   

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

A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. We may not be able to generate sufficient cash flows to pay the principal or interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets or have a portion of our assets foreclosed upon which could have a material adverse effect on our business and financial results.

Our Success Depends, to a Large Extent, on Our Ability to Retain Our Key Personnel, Including Our Chairman of the Board, Chief Executive Officer and President, the Members of Our Board of Directors and Our Special Board Advisors, and the Loss of Any Key Personnel, Board Member or Special Board Advisor Could Disrupt Our Business Operations.

Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued

 

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employment of our management and technical personnel, including our Chairman, President and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals remain in our employment. If Mr. Foran or any of these other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

We have an active board of directors that meets several times throughout the year and is intimately involved in our business and the determination of our operational strategies. Members of our board of directors work closely with management to identify potential prospects, acquisitions and areas for further development. Many of our directors have been involved with us since our inception and have a deep understanding of our operations and culture. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and as a result, our operations may be adversely affected.

In addition, our board consults regularly with our special advisors regarding our business and the evaluation, exploration, engineering and development of our prospects. Due to the knowledge and experience of our special advisors, they play a key role in our multi-disciplined approach to making decisions regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to continue in their present role, our operations may be adversely affected.

Our Management Team Will Own Approximately 12.7% of Our Common Stock after the Consummation of this Offering, Which Could Give Them Influence in Corporate Transactions and Other Matters, and the Interests of Our Management Could Differ From Yours.

Our directors and officers will beneficially own approximately 12.7% of our outstanding shares of common stock following this offering based on a total of 54,719,860 shares of common stock outstanding upon consummation of this offering. These shareholders will be positioned to influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the company may have the effect of delaying or preventing a change of control of the company and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, they may be able to remain entrenched in their positions.

Risks Relating to this Offering and Our Common Stock

The Market Price and Trading Volume of Our Common Stock May Be Volatile Following this Offering.

The market price of our common stock could vary significantly as a result of a number of factors. In addition, the trading volume of our common stock may fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include:

 

   

our actual or anticipated operating and financial performance and drilling locations, including reserves estimates;

 

   

quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us;

 

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changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts;

 

   

speculation in the press or investment community;

 

   

public reaction to our press releases, announcements and filings with the Securities and Exchange Commission, or SEC;

 

   

sales of our common stock by us, the selling shareholders or other shareholders, or the perception that such sales may occur;

 

   

general financial market conditions and oil and gas industry market conditions, including fluctuations in commodity prices;

 

   

the realization of any of the risk factors presented in this prospectus;

 

   

the recruitment or departure of key personnel;

 

   

commencement of or involvement in litigation;

 

   

the prices of oil and natural gas;

 

   

the success of our exploration and development operations, and the marketing of any oil and natural gas we produce;

 

   

changes in market valuations of companies similar to ours; and

 

   

domestic and international economic, legal and regulatory factors unrelated to our performance.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.

There Is Currently No Public Market for Our Common Stock, and an Active Liquid Trading Market for Our Common Stock May Not Develop Following this Offering.

Prior to this offering, there has been no public market for our common stock. Our common stock has been approved for listing on the New York Stock Exchange, or NYSE. Liquid and active trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. Our common stock may have limited trading volume, and many investors may not be interested in owning our common stock because of the inability to acquire or sell a substantial block of our common stock at one time. Such illiquidity could have an adverse effect on the market price of our common stock. In addition, a shareholder may not be able to borrow funds using our common stock as collateral because lenders may be unwilling to accept the pledge of securities having such a limited market. We cannot assure you that an active trading market for our common stock will develop or, if one develops, be sustained.

The Initial Public Offering Price of Our Common Stock May Not Be Indicative of the Market Price of Our Common Stock after this Offering.

The initial public offering price may not necessarily bear any relationship to our book value or the fair market value of our assets. The initial public offering price has been negotiated between us and representatives of the underwriters, based on numerous factors which we discuss in the “Underwriters” section of this prospectus, and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering.

 

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Purchasers of Common Stock in this Offering will Experience Immediate and Substantial Dilution of $4.71 Per Share.

Based on the initial public offering price of $12.00 per share, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $4.71 per share in the pro forma as adjusted net tangible book value per share of common stock from the initial public offering price, and our pro forma as adjusted net tangible book value at September 30, 2011 after giving effect to this offering would be $7.29 per share. See “Dilution” for a complete description of the calculation of net tangible book value.

Our Intended Use of the Net Proceeds We Receive from this Offering is as Set Forth Under “Use of Proceeds” in this Prospectus, but Our Budgets May Change Throughout 2012 Depending on Oil and Natural Gas Prices, the Outcome of Our Drilling and Exploration Programs and Proposed Acquisitions.

As we discuss in the “Use of Proceeds” section in this prospectus, we intend to use the net proceeds we receive from this offering and from any exercise of the underwriters’ over-allotment option to repay the then outstanding borrowings under our credit agreement and to fund a portion of our anticipated 2012 capital expenditure budget. To the extent we repay borrowings under our credit agreement, additional borrowings will be available to be used to fund our 2012 capital expenditure budget. However, we may determine to revise our 2012 capital expenditure budget based on the then current oil and natural gas prices and the outcome of our drilling programs. In addition, we may spend some of the net proceeds we receive from this offering or additional borrowings under our credit agreement to consummate acquisitions of interests and acreage not contemplated by our 2012 capital expenditure budget if we are presented with attractive acquisition opportunities. Management has broad discretion in applying the net proceeds we receive from this offering. Our shareholders may not agree with the manner in which our management chooses to allocate and spend the net proceeds we receive from this offering. The failure of management to apply these funds effectively will have a material adverse effect on our business, financial condition, results of operations and cash flows. Pending their use, we may invest our net proceeds from this offering in a manner that does not produce income or that loses value.

Because We Are a Relatively Small Company, the Requirements of Being a Public Company, Including Compliance with the Reporting Requirements of the Securities Exchange Act of 1934, as Amended, and the Requirements of the Sarbanes-Oxley Act, May Strain Our Resources, Increase Our Costs and Distract Management; and We May Be Unable to Comply with these Requirements in a Timely or Cost-Effective Manner.

As a public company with listed equity securities, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley Act, related regulations of the SEC and the requirements of the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses, which we cannot estimate accurately at this time. We will need to:

 

   

institute a more comprehensive compliance function;

 

   

establish and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;

 

   

comply with rules promulgated by the NYSE;

 

   

prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

 

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establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;

 

   

involve and retain to a greater degree outside counsel and accountants in the above activities;

 

   

establish an internal audit function; and

 

   

establish an investor relations function.

In addition, we also expect that being a public company subject to these rules and regulations may require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers.

If Any of the Material Weaknesses Previously Identified by Our Independent Registered Public Accountants Persist or if We Fail to Establish and Maintain Effective Internal Control over Financial Reporting in the Future, Our Ability to Accurately Report Our Financial Results Could Be Adversely Affected.

Prior to the completion of this offering, we have been a private company and have maintained internal controls and procedures in accordance with being a private company. We have maintained limited accounting personnel to perform our accounting processes and limited supervisory resources with which to address our internal control over financial reporting. In connection with our audit for the year ended December 31, 2010, our independent registered public accountants identified and communicated material weaknesses related to accounting for deferred income taxes, impairment of oil and natural gas properties, assessment of unproved and unevaluated properties and the administration of our stock plan. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual and interim financial statements will not be prevented or detected on a timely basis.

We have begun the process of evaluating our internal control over financial reporting and will continue to work with our auditors to put into place new accounting process and control procedures to address the issues set forth above. However, we will not complete this process until well after this offering is completed. We cannot predict the outcome of this process at this time.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and to provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting until the year following the year that our first annual report is filed or required to be filed with the SEC. To comply with the requirements of being a public company, we will need to upgrade our systems, including information technology, implement additional financial and management controls, reporting systems and procedures and hire additional accounting and financial reporting staff.

Further, our independent registered public accountants are not yet required to formally attest to the effectiveness of our internal control over financial reporting until the year following the year that our first

 

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annual report is required to be filed with the SEC. Once they are required to do so, our independent registered public accountants may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Our remediation efforts may not enable us to remedy or avoid material weaknesses in the future.

Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Further, our remediation efforts may not enable us to remedy or avoid material weaknesses in the future. Any failure to remediate deficiencies and to develop or maintain effective controls, or any difficulties encountered in our implementation or improvement of our internal control over financial reporting, could result in material misstatements that are not prevented or detected on a timely basis, which could potentially subject us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information.

We Do Not Presently Intend to Pay Any Cash Dividends on or Repurchase Any Shares of Our Common Stock.

We do not presently intend to pay any cash dividends on our common stock. Any payment of future dividends will be at the discretion of the board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. In addition, certain covenants in our credit agreement may limit our ability to pay dividends or repurchase shares of our common stock. While these prohibitions exist, we are prohibited from the payment of dividends and the repurchase of shares of our common stock without a waiver from our lenders. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment and there is no guarantee that the price of our common stock that will prevail in the market after this offering may never exceed the price paid by you in this offering.

Future Sales of Shares of Our Common Stock by Existing Shareholders and Future Offerings of Our Common Stock by Us Could Depress the Price of Our Common Stock.

The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market after this offering, and the perception that these sales could occur may also depress the market price of our common stock. Based on 43,053,193 shares outstanding at January 16, 2012, upon completion of this offering, we will have outstanding approximately 54,719,860 shares of common stock, and in addition to the shares sold in this offering, 54,584,284 shares of common stock will be immediately freely tradable, without restriction, in the public market, except to the extent the shares are held by any of our affiliates. 42,440,339 of our shares, including all shares held by our officers, directors and selling shareholders (without taking into account the shares sold by the selling shareholders), are subject to lock-up agreements that prohibit the disposition of those shares during the 180-day period beginning on the date of the final prospectus related to this offering, except with the prior written consent of RBC Capital Markets, LLC and subject to certain exceptions. After the expiration of the 180-day restricted period, all of these shares may be sold in the public market in the United States, subject to prior registration in the United States, if required, or reliance upon an exemption from U.S. registration, including, in the case of shares held by affiliates or control persons, compliance with the volume restrictions of Rule 144.

 

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If our existing shareholders sell, or indicate an intent to sell, substantial amounts of our common stock in the public market after any contractual lockup and other legal restrictions on resale discussed in this prospectus lapse, the trading price of our common stock could decline significantly and could decline below the initial public offering price. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales also could cause our stock price to fall and make it more difficult for you to sell shares of our common stock.

As soon as practicable after effectiveness of the registration statement of which this prospectus is a part, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of 4,739,500 shares of our common stock issuable or reserved for issuance under our 2003 Stock and Incentive Plan and our 2012 Long-Term Incentive Plan. Subject to the satisfaction of vesting conditions, the expiration of lockup agreements and certain restrictions on sales by affiliates, shares registered under a registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

We may also sell additional shares of common stock or securities convertible into common stock in subsequent offerings. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities will have on the market price of our common stock.

Provisions of Our Certificate of Formation, Bylaws and Texas Law May Have Anti-Takeover Effects that Could Prevent a Change in Control Even if It Might Be Beneficial to Our Shareholders.

Our certificate of formation and bylaws contain, or will contain upon completion of this offering, certain provisions that may discourage, delay or prevent a merger or acquisition that our shareholders may consider favorable. These provisions include:

 

   

authorization for our board of directors to issue preferred stock without shareholder approval;

 

   

a classified board of directors so that not all members of our board of directors are elected at one time;

 

   

the prohibition of cumulative voting in the election of directors; and

 

   

a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock.

Provisions of Texas law also may discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or any “affiliated shareholder,” cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our board of directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder. See “Description of Capital Stock — Business Combinations Under Texas Law.”

 

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Our Board of Directors can Authorize the Issuance of Preferred Stock, which Could Diminish the Rights of Holders of Our Common Stock, and Make a Change of Control of the Company More Difficult Even if it might Benefit Our Shareholders.

Our board of directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock. Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the company, even if that change of control might benefit our shareholders.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs and cash flows, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “should,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements may include statements about our:

 

   

business strategy;

 

   

reserves;

 

   

technology;

 

   

cash flows and liquidity;

 

   

financial strategy, budget, projections and operating results;

 

   

oil and natural gas realized prices;

 

   

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

 

   

availability of drilling and production equipment;

 

   

availability of oil field labor;

 

   

the amount, nature and timing of capital expenditures, including future exploration and development costs;

 

   

availability and terms of capital;

 

   

drilling of wells;

 

   

competition and government regulations;

 

   

marketing of oil and natural gas;

 

   

exploitation projects or property acquisitions;

 

   

costs of exploiting and developing our properties and conducting other operations;

 

   

general economic conditions;

 

   

competition in the oil and natural gas industry;

 

   

effectiveness of our risk management and hedging activities;

 

   

environmental liabilities;

 

   

counterparty credit risk;

 

   

governmental regulation and taxation of the oil and natural gas industry;

 

   

developments in oil-producing and natural gas-producing countries;

 

   

uncertainty regarding our future operating results;

 

   

estimated future reserves and present value thereof; and

 

   

plans, objectives, expectations and intentions contained in this prospectus that are not historical.

 

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All forward-looking statements speak only at the date of this prospectus. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this prospectus are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this prospectus. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. We do not undertake any obligation to update or revise publicly any forward-looking statements except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.

 

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USE OF PROCEEDS

We will receive net proceeds of approximately $127.6 million from the sale of the common stock offered by us after deducting estimated expenses of approximately $3.0 million and estimated underwriting discounts and commissions of approximately $9.4 million. If the underwriters’ over-allotment option is exercised in full, we estimate that our net proceeds will be approximately $135.4 million. We will not receive any proceeds from the sale of shares of our common stock by the selling shareholders, including with respect to any sale of shares by the selling shareholders as a result of the exercise of the underwriters’ over-allotment option.

Initially, we intend to use the net proceeds we receive from this offering to repay the then outstanding borrowings under our credit agreement ($123.0 million outstanding at January 27, 2012, excluding outstanding letters of credit). Following the application of the net proceeds we receive from this offering, we will have approximately $98.7 million available for potential future borrowings under our credit agreement (after giving effect to outstanding letters of credit). We intend to use the remaining net proceeds from this offering, our cash from operations and available borrowings under our credit agreement to fund our 2012 capital expenditure requirements. As a result of our anticipated increases in production and reserves, we expect to have a sufficient increase in our cash flows from operations during the year ending December 31, 2012, as compared to our cash flows from operations in prior periods, as well as a sufficient increase in the borrowing base under our credit agreement to help fund our 2012 capital expenditure budget. A majority of our anticipated increase in cash flows during the year ending December 31, 2012 is expected to come from our exploration activities on unproved properties at September 30, 2011 in the Eagle Ford shale play assuming such exploration activities are successful. These anticipated increases in our cash flows from operations are based upon current oil and natural gas prices and the hedges we currently have in place. If our exploration activities result in less cash flows than anticipated, we may seek additional sources of capital, including through borrowings under our credit agreement (assuming availability under our borrowing base) or from the issuance of additional equity or debt securities. In addition, we may modify our planned capital expenditure budget for 2012 accordingly. Exploration activities are subject to a number of risks and uncertainties that could impact our ability to sufficiently increase our reserves, cash flows from operations and borrowing base under our credit agreement. See “Risk Factors — Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows From Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth” and “—Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties That Could Adversely Affect Our Business.” Although we have no current plans or proposals, pending application of the portion of our net proceeds to fund our 2012 capital expenditure requirements, we may be presented with other opportunities for acquisitions of interests or acreage. In that case, we may decide to use a portion of the net proceeds to finance these acquisitions and use cash flows from operations or additional borrowings under our credit agreement to fund our 2012 capital expenditure requirements, when necessary.

We intend to use the following amounts of the net proceeds for the above uses:

 

Use of Net Proceeds

   Amount
(in millions)
 

Repayment of senior secured revolving credit agreement

   $ 123.0   

Payment of a portion of 2012 capital expenditure requirements

     4.6   
  

 

 

 

Total net proceeds

   $ 127.6   

 

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In December 2011, we amended and restated our senior secured revolving credit agreement. This amendment increased the maximum facility amount from $150 million to $400 million. Borrowings are limited to the lesser of $400 million or the borrowing base, which will be $100 million immediately following this offering. Comerica Bank serves as administrative agent of our credit agreement, which matures in December 2016. At January 27, 2012, all borrowings under our credit agreement bore interest at a variable rate of 3.25% plus a Eurodollar-based rate per annum, which equated to approximately 3.5% per annum. For more information regarding our amended and restated credit agreement, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreement.” Affiliates of certain of the underwriters are lenders under our senior secured revolving credit agreement and, accordingly, will receive a portion of the proceeds from this offering. Please read “Underwriting — Conflicts of Interest.”

Borrowings under the credit agreement were incurred from December 2010 through January 2012 to finance acquisitions of acreage and ongoing drilling and completion operations. Upon consummation of this offering and application of the net proceeds we receive in the manner described above, we will have available borrowings under our credit agreement to finance our capital expenditure requirements. We anticipate that we may need to access future borrowings under our credit agreement within 30 days following completion of this offering to fund a portion of our 2012 capital expenditure requirements in excess of amounts available from our cash flows and the net proceeds of this offering.

The selling shareholders will receive net proceeds of approximately $18.8 million from their sale of 1,666,667 shares of common stock in this offering, or approximately $33.4 million if the underwriters exercise their over-allotment option in full, and in each case after deducting estimated underwriting discounts and commissions. We will pay all expenses related to this offering, other than underwriting discounts and commissions related to the shares sold by the selling shareholders. Certain selling shareholders that are selling 243,460 shares in this offering will not be required to pay underwriting discounts or commissions. See “Principal and Selling Shareholders” and “Underwriters.”

While we expect to use the net proceeds from this offering in the manner described above, including for potential acquisitions of interests and/or acreage (although we have no current plans to do so), the ultimate amount of capital we will expend may fluctuate materially based on market conditions and our drilling results. Our future financial condition and liquidity will be impacted by, among other factors, our level of production of oil and natural gas and the prices we receive from the sale thereof, the outcome of our exploration and drilling programs, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, and the actual cost of exploration and development of our oil and natural gas assets. We intend to invest any net proceeds from this offering that exceed the pay off amount of our credit agreement as described above in U.S. treasury bonds or investment grade instruments until otherwise needed.

 

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DIVIDEND POLICY

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, certain covenants in our credit agreement may limit our ability to pay dividends on our common stock.

In addition, prior to consummation of this offering, the holders of our Class B common stock are entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of funds legally available for the payment of dividends. These dividends accrue and are payable quarterly at the rate of $0.06-2/3 per share of Class B common stock outstanding. For the years ended December 31, 2010 and 2009, we declared dividends on our outstanding shares of Class B common stock totaling $274,853 in each year. For the nine months ended September 30, 2011, we declared dividends on our outstanding shares of Class B common stock totaling $206,140. Upon the automatic conversion of the outstanding shares of Class B common stock at the closing of this offering, the right of the holders of Class B common stock to dividends will terminate. Any accrued but unpaid dividends existing at the time of such conversion will be paid to the holders of the Class B common stock upon conversion.

 

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CAPITALIZATION

The following table sets forth our capitalization at September 30, 2011. Our capitalization is presented:

 

   

on an actual basis; and

 

   

on an as adjusted basis to give effect to this offering (assuming aggregate net proceeds of $127.6 million are received by us), the application of the estimated net proceeds to be received by us to repay then outstanding borrowings under our credit agreement ($123.0 million outstanding at January 27, 2012, excluding outstanding letters of credit), with the balance being added to cash and cash equivalents until it is used to fund capital requirements, the issuance of 285,000 shares of common stock by us to certain holders of stock options prior to consummation of this offering in connection with the exercise of their stock options at an exercise price of $9.00 per share and the conversion of our Class B common stock into Class A common stock upon consummation of this offering.

You should read the following table in conjunction with “Use of Proceeds,” “Selected Historical Consolidated and Other Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and related notes thereto appearing elsewhere in this prospectus.

 

     At September 30, 2011  
     Actual     As Adjusted  
(In thousands except for shares)     

Cash and cash equivalents

   $ 7,768      $ 14,883   

Certificates of deposit

     2,085        2,085   

Debt:

    

Short-term debt

     25,000          

Long-term debt(1)

     60,000          

Shareholders’ equity:

    

Class A common stock, $0.01 par value, 80,000,000 shares authorized; 42,907,843 shares issued and 41,728,668 shares outstanding, actual; 55,890,210 shares issued and 54,711,035 shares outstanding, as adjusted

     429        559   

Class B common stock, $0.01 par value, 2,000,000 shares authorized; 1,030,700 shares issued and outstanding, actual; 0 shares issued and outstanding, as adjusted

     10          

Additional paid-in capital

     263,933        393,928   

Retained earnings

     14,931        14,931   

Treasury stock, at cost, 1,179,175 shares

     (10,765     (10,765
  

 

 

   

 

 

 

Total shareholders’ equity

   $ 268,538      $ 398,653   
  

 

 

   

 

 

 

Total capitalization

   $ 328,538      $ 398,653   
  

 

 

   

 

 

 

 

(1) At January 27, 2012, the borrowing base under our credit agreement was $125.0 million, and we had $123.0 million in borrowings outstanding, excluding outstanding letters of credit. Approximately $0.7 million remained available for additional borrowings. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreement.”

 

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DILUTION

Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our net tangible book value at September 30, 2011 was approximately $269 million, or $6.28 per share of common stock. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of common stock that will be outstanding immediately prior to the closing of this offering.

After giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds to be received by us (after deducting estimated discounts and expenses of this offering), our as adjusted net tangible book value at September 30, 2011 would have been approximately $398.7 million, or $7.29 per share. This represents an immediate increase in the net tangible book value of $1.01 per share to our existing shareholders and an immediate dilution (i.e., the difference between the offering price and the adjusted net tangible book value after this offering) to new investors purchasing shares in this offering of $4.71 per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering:

 

Assumed initial public offering price per share

      $12.00   

Net tangible book value per share at September 30, 2011

   
6.28
  
 

Increase per share attributable to new investors in this offering

    1.01     
 

 

 

   

As adjusted net tangible book value per share after giving effect to this offering

      7.29   
   

 

 

 

Dilution in as adjusted net tangible book value per share to new investors in this offering

      $  4.71   
   

 

 

 

The following table summarizes, on an as adjusted basis at September 30, 2011, the total number of shares of common stock owned by existing shareholders (assuming (i) the issuance by us of 285,000 shares of common stock to certain holders of stock options prior to consummation of this offering in connection with the exercise of their stock options at an exercise price of $9.00 per share and (ii) the conversion of our Class B common stock as described under “Description of Capital Stock”) and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing shareholders and to be paid by new investors in this offering at $12.00, calculated before deduction of estimated underwriting discounts and commissions:

 

     Shares Acquired     Total Consideration     Average Price
per Share
     Number      Percent     Amount      Percent    

Existing shareholders(1)

     43,044,368         78.7        $256,738         64.7      $  5.96

New investors(1)

     11,666,667         21.3        140,000         35.3        12.00
  

 

 

    

 

 

   

 

 

    

 

 

   

Total

     54,711,035         100.0     $396,738         100.0   $  7.25
  

 

 

    

 

 

   

 

 

    

 

 

   

 

(1) The number of shares disclosed for the existing shareholders includes 1,666,667 shares being sold by the selling shareholders in this offering. The number of shares disclosed for the new investors does not include the shares being purchased by the new investors from the selling shareholders in this offering.

Apart from the information set forth in the tables above, assuming the underwriters’ over-allotment is exercised in full, sales by us in this offering will reduce the percentage of shares held by existing shareholders, without giving effect to the shares being sold by the selling shareholders in this offering, to 77.7% and will increase the number of shares held by new investors to 12,366,667, or 22.3% on an as adjusted basis at September 30, 2011.

 

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SELECTED HISTORICAL CONSOLIDATED AND OTHER FINANCIAL DATA

You should read the following selected financial data in conjunction with “Corporate Reorganization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and related notes thereto included elsewhere in this prospectus. The financial information included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.

The following selected financial information is summarized from our results of operations for the five-year period ended December 31, 2010 and selected consolidated balance sheet data at December 31, 2010, 2009, 2008, 2007 and 2006 and our results of operations for the nine months ended September 30, 2011 and 2010 and the consolidated balance sheet data at September 30, 2011 and 2010 and should be read in conjunction with the consolidated financial statements at the years ended December 31, 2010, 2009 and 2008 and the nine month periods ended September 30, 2011 and 2010, and the notes thereto included herewith.

 

    Year Ended December 31,     Nine Months  Ended
September 30,
 
    2010     2009     2008     2007     2006     2011     2010  
                                 

(Unaudited)

   

(Unaudited)

 
(In thousands)                                          

Statement of operations data:

             

Revenues:

             

Oil and natural gas revenues

  $ 34,042      $ 19,039      $ 30,645      $ 13,988      $ 14,678      $ 52,009      $ 25,182   

Realized gain (loss) on derivatives

    5,299        7,625        (1,326     213               4,237        2,988   

Unrealized gain (loss) on derivatives

    3,139        (2,375     3,592        (211            1,534        5,813   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

    42,480        24,289        32,911        13,990        14,678        57,780        33,983   

Expenses:

             

Production taxes and marketing

    1,982        1,077        1,639        779        896        4,801        1,235   

Lease operating

    5,284        4,725        4,667        3,099        3,075        5,639        3,801   

Depletion, depreciation and amortization

    15,596        10,743        12,127        7,889        10,950        22,578        10,931   

Accretion of asset retirement obligations

    155        137        92        70        55        158        107   

Full-cost ceiling impairment

           25,244        22,195               56,504        35,673          

General and administrative

    9,702        7,115        8,252        5,189        5,407        9,395        6,793   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

    32,719        49,041        48,972        17,026        76,887        78,244        22,867   

Operating income (loss)

    9,761        (24,752     (16,061     (3,036     (62,209     (20,464     11,116   

Other income (expense):

             

Net gain (loss) on asset sales and inventory impairment

    (224     (379     136,977                               

Interest and other income

    364        781        2,984        2,736        2,063        248        300   

Interest expense

    (3                                 (461       
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

    137        402        139,962        2,736        2,063        (213     300   

Net income (loss)

  $ 6,377      $ (14,425   $ 103,878      $ (300   $ (60,146   $ (13,725   $ 7,373   

 

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    At December 31,     At September 30,  
    2010     2009     2008     2007     2006     2011     2010  
                                  Actual     As
Adjusted(1)
       
                                 

(Unaudited)

   

(Unaudited)

   

(Unaudited)

 
(In thousands)      

Balance sheet data:

               

Cash and cash equivalents

  $ 21,060      $ 104,230      $ 150,768      $ 9,017      $ 43,183      $ 7,768      $ 14,883      $ 38,618   

Certificates of deposit

    2,349        15,675        20,782                      2,085        2,085        7,429   

Short-term investments

                         57,925                               

Net property and equipment

    303,880        142,078        125,261        105,814        63,062        350,279        388,279        227,052   

Total assets

    346,382        277,400        314,539        179,152        112,628        383,244        428,359        291,423   

Current liabilities

    30,097        8,868        35,475        5,541        5,878        50,102        25,102        19,396   

Long term liabilities

    34,408        4,210        2,059        1,568        878        64,604        4,604        8,125   

Total shareholders’ equity

  $ 281,877      $ 264,321      $ 277,005      $ 172,043      $ 105,872      $ 268,538      $ 398,653      $ 263,902   

 

     Year Ended December 31,     Nine Months Ended
September 30,
 
     2010     2009     2008     2007     2006     2011     2010  
                                  

(Unaudited)

   

(Unaudited)

 
(In thousands)       

Other financial data:

              

Net cash provided by operating activities

   $ 27,273      $ 1,791      $ 25,851      $ 7,881      $ 1,570      $ 34,443      $ 21,390   

Net cash (used in) provided by investing activities

     (147,334     (49,415     115,481        (108,296     (49,501     (107,772     (78,718

Oil and natural gas properties capital expenditures

     (159,050     (54,244     (104,119     (50,310     (51,932     (104,733     (86,031

Expenditures for other property and equipment

     (1,610     (307     (3,012     (1,300     (3,127     (3,303     (934

Net cash provided by (used in) financing activities

     36,891        1,086        419        66,250        73,876        60,037        (8,284

Adjusted EBITDA(2)

   $ 23,635      $ 15,184      $ 18,411      $ 8,091      $ 7,582      $ 37,550      $ 17,133   

 

(1) As adjusted to give effect to (a) this offering (assuming aggregate net proceeds of $127.6 million are received by us), (b) the application of the net proceeds to be received by us to repay the then outstanding borrowings under our credit agreement ($123.0 million less outstanding letters of credit), (c) $38.0 million being added to property and equipment reflecting the use of $38.0 million in additional borrowings under our credit agreement between September 30, 2011 and January 27, 2012, (d) the balance of the net proceeds from this offering being added to cash and cash equivalents to fund a portion of our 2012 capital expenditure budget and (e) the proceeds to be received by us as a result of the issuance of 285,000 shares of common stock to certain holders of stock options prior to the consummation of this offering in connection with the exercise of their stock options at an exercise price of $9.00 per share.

 

(2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Summary Financial, Reserves and Operating Data.”

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this prospectus. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in the prospectus, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.”

Overview

We are an independent energy company engaged in the exploration, development, acquisition and production of oil and natural gas resources in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resources. Our current operations are located primarily in the Eagle Ford shale play in south Texas and the Haynesville shale play in northwest Louisiana and east Texas. These plays are a key part of our growth strategy, and we believe they currently represent two of the most active and economically viable unconventional resource plays in North America. We expect the majority of our near-term capital expenditures will focus on increasing our production and reserves from the Eagle Ford and Haynesville shale plays as we seek to capitalize on the relative economics of each play. In addition to these primary operating areas, we have significant acreage positions in southeast New Mexico and west Texas and in southwest Wyoming and adjacent areas in Utah and Idaho where we continue to identify new oil and natural gas prospects.

We were founded in July 2003 by Mr. Joseph Wm. Foran and Mr. Scott E. King, and we drilled our first well in 2004. Since that time, we have drilled or participated in 213 wells through September 30, 2011, including 83 Haynesville and six Eagle Ford wells. At September 30, 2011, based on the reserves audit by our independent reservoir engineers, we had 161.8 Bcfe of estimated proved reserves with a PV-10 of $155.2 million and a Standardized Measure of $143.4 million. At September 30, 2011, 35% of our estimated proved reserves were proved developed reserves and 96% of our estimated proved reserves were natural gas. We grew our average daily production by 162% from 9.0 MMcfe per day from the year ended December 31, 2008 to 23.6 MMcfe per day for the year ended December 31, 2010. As a result of initial production from several wells that were completed in 2011, our average daily production for the nine months ended September 30, 2011 was approximately 42.5 MMcfe per day.

Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk factor for us. Commodity prices are affected by changes in market supply and demand, which is impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, natural gas price differentials and other factors. Prices for oil and natural gas will affect the cash flows available to us for capital expenditures and our ability to borrow

 

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and raise additional capital. Declines in oil or natural gas prices would not only reduce our revenues, but could also reduce the amount of oil and/or natural gas that we can produce economically, and as a result, could have an adverse effect on our financial condition, results of operations, cash flows and reserves. Because we produce more natural gas than oil at the present time and expect to continue to do so in the near term, we will face more risks associated with fluctuations in the price of natural gas. Since one of our current business strategies is to focus on increasing our oil and liquids production, we will face increased risk in the future associated with fluctuations in the price of oil.

In response to the recent commodity price environment, and in particular, the general decline in natural gas prices since July 2008 in contrast with the rebound in oil prices since February 2009, we have sought to balance our exploration and development plans by targeting more oil prone reservoirs, such as the Eagle Ford shale. While most of our historical and current production is natural gas, we believe that our future production profile will reflect a more balanced oil and natural gas commodity mix as a result of our strategic shift to target more oil development than we have historically.

One of the biggest challenges we face in the development of our Eagle Ford and Haynesville shale acreage is associated with service costs, and particularly in the Eagle Ford play, pipeline infrastructure and the shortage of stimulation equipment and service dates necessary to stimulate these wells. Due to the increased activity in these areas, service costs have continued to rise and the availability of completion crews has decreased. We believe that reducing drilling and particularly completion costs will be essential to the successful development and profitability of the Eagle Ford and Haynesville shale plays. See “Risk Factors — The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our financial condition, results of operations and cash flows.”

We believe that our general and administrative expenses will increase in connection with the completion of this offering as a result of us operating as a public company. This increase will consist primarily of legal and accounting fees and additional expenses associated with compliance with the Sarbanes-Oxley Act and other regulations and increases in our staff compensation and other ongoing general and administrative expenses necessary to maintain and grow a publicly traded exploration and production company. A large part of this increase will be due to the cost of accounting support services, filing annual and quarterly reports with the SEC, investor relations activities, directors’ fees, incremental directors’ and officers’ liability insurance costs and transfer and registrar agent fees. As a result, we believe that our general and administrative expenses for future periods will increase significantly. Our consolidated financial statements following the completion of this offering will reflect the impact of these increased expenses and affect the comparability of our financial statements with periods before the completion of this offering.

Revenues

Our revenues are derived primarily from the sale of oil and natural gas production. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in oil or natural gas prices.

Realized gain (loss) on derivatives. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in natural gas prices. This revenue item includes the net realized cash gains and losses associated with the settlement of these derivative financial instruments for a given reporting period.

 

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Unrealized gain (loss) on derivatives. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in natural gas prices. This revenue item recognizes the non-cash change in the fair value of our open derivative contracts between reporting periods.

The following table summarizes our revenues and production data for the periods indicated:

 

     Year Ended December 31,     Nine Months Ended
September 30,
 
     2010      2009     2008     2011      2010  
                        (Unaudited)      (Unaudited)  

Operating Results:

            

Revenues (in thousands):

            

Oil

   $ 2,506       $ 1,719      $ 3,653      $ 10,468       $ 1,831   

Natural gas

     31,535         17,320        26,992        41,541         23,351   
  

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

Total oil and natural gas revenues

     34,042         19,039        30,645        52,009         25,182   

Realized gain (loss) on derivatives

     5,299         7,625        (1,326     4,237         2,988   

Unrealized gain (loss) on derivatives

     3,139         (2,375     3,592        1,534         5,813   
  

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

Total revenues

   $ 42,480       $ 24,289      $ 32,911      $ 57,780       $ 33,983   

Net Production Volumes:

            

Oil (MBbls)

     33         30        37        113         24   

Natural gas (Bcf)

     8.4         4.8        3.1        10.9         5.9   

Total natural gas equivalents (Bcfe)

     8.6         5.0        3.3        11.6         6.0   

Average net daily production (MMcfe/d)

     23.6         13.7        9.0        42.5         22.0   

Average Sales Prices:

            

Oil (per Bbl)

   $ 76.39       $ 57.72      $ 98.59      $ 92.71       $ 74.59   

Natural gas, with realized derivatives (per Mcf)

   $ 4.38       $ 5.17      $ 8.32      $ 4.19       $ 4.49   

Natural gas, without realized derivatives (per Mcf)

   $ 3.75       $ 3.59      $ 8.75      $ 3.80       $ 3.98   

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Oil and natural gas revenues. Our oil and natural gas revenues increased by $26.8 million to $52.0 million, or an increase of about 107%, for the nine months ended September 30, 2011, as compared to the nine months ended September 30, 2010. This increase in oil and natural gas revenues corresponds with an increase of about 93% in our oil and natural gas production to 11.6 Bcfe for the nine months ended September 30, 2011 from 6.0 Bcfe for the nine months ended September 30, 2010. This increased production was primarily due to drilling operations in the Haynesville shale, but also reflects initial production from our first two operated wells in the Eagle Ford shale. A portion of the increased oil and natural gas revenues was also attributable to the approximate five-fold increase in our oil production for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010, as well as to the increase of about $18.00 per Bbl in the average price we received for this oil production during the nine months ended September 30, 2011 as compared to the same period in 2010.

Realized gain (loss) on derivatives. Our realized gain on derivatives increased by approximately $1.2 million to $4.2 million for the nine months ended September 30, 2011 from $3.0 million for the nine months ended September 30, 2010. The realized gain from our open natural gas costless collar contracts increased primarily as a result of the decline in natural gas prices during the comparable periods. We realized approximately $0.91 per MMBtu hedged on all of our open natural gas costless collar contracts during the nine months ended September 30, 2011 as compared to $0.68 per MMBtu hedged on all of our open natural gas costless collar contracts during the nine months ended September 30, 2010.

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was $1.5 million for the nine months ended September 30, 2011, compared to an unrealized gain of $5.8 million for the nine months

 

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ended September 30, 2010. During the period from December 31, 2010 to September 30, 2011, the net fair value of our open natural gas costless collar contracts increased from $4.1 million to $5.6 million, resulting in an unrealized gain on derivatives of $1.5 million for the nine months ended September 30, 2011. This increase in the net fair value of our open natural gas costless collar contracts was due primarily to a decrease in natural gas prices during the first nine months of 2011 as compared to the comparable period in 2010, as well as an increase in the total number of our open contracts at September 30, 2011 as compared to December 31, 2010. During the period from December 31, 2009 to September 30, 2010, the net fair value of our open natural gas costless collar contracts increased from $1.0 million to $6.8 million, resulting in an unrealized gain on derivatives of $5.8 million for the nine months ended September 30, 2010.

Year Ended December 31, 2010 as Compared to Year Ended December 31, 2009

Oil and natural gas revenues. Our oil and natural gas revenues increased by $15.0 million to $34.0 million, or an increase of about 79%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. Approximately $13.7 million of the increase was primarily due to a 72% increase in our production to 8.6 Bcfe during the year ended December 31, 2010 from 5.0 Bcfe during the year ended December 31, 2009, and approximately $1.3 million of the increase was due to increases in the average prices we received for both oil and natural gas over these respective periods. For the year ended December 31, 2010, we received an average natural gas price of $3.75 per Mcf and an average oil price of $76.39 per Bbl as compared to an average natural gas price of $3.59 per Mcf and an average oil price of $57.72 per Bbl for the year ended December 31, 2009. Our increased production during this period was primarily due to drilling operations in the Haynesville shale.

Realized gain (loss) on derivatives. Our realized gain on derivatives decreased by approximately $2.3 million to $5.3 million for the year ended December 31, 2010 from $7.6 million for the year ended December 31, 2009. This decrease was due primarily to a decrease of about $1.50 per MMBtu in the average price floor of our open natural gas costless collar contracts in 2010 as compared with 2009 and despite the increase in natural gas volumes hedged in 2010 as compared to 2009.

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was $3.1 million for the year ended December 31, 2010, compared to an unrealized loss of $2.4 million for the year ended December 31, 2009. During the period from December 31, 2009 to December 31, 2010, the net fair value of our open natural gas costless collar contracts increased from $1.0 million to $4.1 million, resulting in an unrealized gain on derivatives of $3.1 million for the year ended December 31, 2010. This increase in the net fair value of our open natural gas costless collar contracts was due primarily to lower natural gas prices at December 31, 2010 as compared to December 31, 2009. During the period from December 31, 2008 to December 31, 2009, the net fair value of our open natural gas costless collar contracts decreased from $3.4 million to $1.0 million, resulting in an unrealized loss on derivatives of $2.4 million for the year ended December 31, 2009. This decrease in the net fair value of our open natural gas costless collar contracts was due primarily to an approximate $2.00 per MMBtu decrease in the average floor price of our open contracts at December 31, 2009 as compared with December 31, 2008.

Year Ended December 31, 2009 as Compared to Year Ended December 31, 2008

Oil and natural gas revenues. Our oil and natural gas revenues decreased $11.6 million to $19.0 million, or a decrease of about 38%, during the year ended December 31, 2009 as compared to the year ended December 31, 2008. Although we increased our production by 51% from 3.3 Bcfe in 2008 to 5.0 Bcfe in 2009, the oil and natural gas revenues of approximately $5.8 million generated by these increased production volumes did not fully offset the $17.4 million decrease in oil and natural gas revenues

 

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attributable to a sharp decline in the prices we received for both oil and natural gas in 2009 as compared with 2008. For the year ended December 31, 2009, we received an average natural gas price of $3.59 per Mcf and an average oil price of $57.72 per Bbl as compared to an average natural gas price of $8.75 per Mcf and an average oil price of $98.59 per Bbl for the year ended December 31, 2008. Our increased production during this period was due primarily to drilling operations in the Haynesville shale.

Realized gain (loss) on derivatives. Our realized gain on derivatives increased approximately $8.9 million to $7.6 million during the year ended December 31, 2009 from a loss of $1.3 million during the year ended December 31, 2008. Natural gas futures prices closed above the price ceiling of many of our open natural gas costless collar contracts during the first half of 2008, and, as a result, we were required to pay the counterparty at settlement. Natural gas prices declined sharply beginning in August 2008 and continued to decline throughout much of 2009, and as a result, natural gas prices closed below the price floor of many of our open costless collar contracts during almost all of 2009. As a result, we received cash from the counterparty at settlement and our realized gain on derivatives increased significantly.

Unrealized gain (loss) on derivatives. Our unrealized loss on derivatives was $2.4 million for the year ended December 31, 2009 as compared to an unrealized gain of $3.6 million for the year ended December 31, 2008. During the period from December 31, 2008 to December 31, 2009, the net fair value of our open natural gas costless collar contracts decreased from $3.4 million to $1.0 million, resulting in an unrealized loss on derivatives of $2.4 million for the year ended December 31, 2009. This decrease in the net fair value of our open natural gas costless collar contracts was due primarily to an approximate $2.00 per MMBtu decrease in the average floor price of our open contracts at December 31, 2009 as compared with December 31, 2008. During the period from December 31, 2007 to December 31, 2008, the net fair value of our open natural gas costless collar contracts increased from a liability of $0.2 million to $3.4 million, resulting in an unrealized gain on derivatives of $3.6 million for the year ended December 31, 2008. This increase in the net fair value of our open natural gas costless collar contracts was due to a decrease in natural gas prices and an increase in the volume of natural gas hedged at December 31, 2008 as compared with December 31, 2007.

Expenses

Production taxes and marketing. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We attempt to take advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay tend to correlate to the changes in our oil and natural gas revenues. Marketing expenses are fees charged by the purchasers of the oil and natural gas we produce and sell and principally include marketing, compression and transportation fees.

Lease operating expenses. Lease operating expenses are the daily costs incurred to produce oil and natural gas, as well as the daily costs incurred to maintain our producing properties. Such costs also include field personnel costs, utilities, chemical additives, salt water disposal, maintenance, repairs and occasional workover expenses related to our oil and natural gas properties.

Depletion, depreciation and amortization. Depletion, depreciation and amortization includes the systematic expensing of the capitalized costs incurred in the acquisition, exploration and development of oil and natural gas. We use the full-cost method of accounting and accordingly, we capitalize all costs associated with the acquisition, exploration and development of oil and natural gas properties, including unproved and unevaluated property costs. Internal costs are capitalized only to the extent they are directly related to acquisition, exploration or development activities and do not include any costs related to

 

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production, selling or general corporate administrative activities. Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved oil and natural gas reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion, depreciation and amortization.

Accretion of asset retirement obligations. Asset retirement obligations relate to the future costs associated with plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. We recognize the fair value of an asset retirement obligation in the period it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or support equipment and facilities on the balance sheet. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in our statement of operations.

Full-cost ceiling impairment. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center ceiling, with any excess above the cost center ceiling charged to operations as a full-cost ceiling impairment. The cost center ceiling is defined as the sum of (a) the present value discounted at 10 percent of future net revenues of proved oil and natural gas reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) income tax effects related to differences between the book and tax basis of the properties involved. Future net revenues from proved non-producing and proved undeveloped reserves are reduced by the estimated costs of developing these reserves. The fair value of our derivative instruments is not included in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes.

General and administrative expenses. General and administrative expenses include, but are not limited to, compensation and benefits for our employees, costs of renting and maintaining our headquarters, office service contracts, board of directors fees, franchise taxes, stock-based compensation expense and accounting, legal and other professional fees.

Other Income (Expense)

Net gain (loss) on asset sales and inventory impairment. This other income (expense) item includes the net gain or loss we experience on infrequent asset sales or impairment charges associated with certain equipment held in inventory. This item also includes infrequent sales of oil and natural gas properties that we consider to be extraordinary when considered in relation to the normal course of our business.

Interest and other income. Interest income includes interest earned periodically on the cash and cash equivalents we hold in money market accounts composed of United States Treasury securities offering daily liquidity and the interest earned periodically on our certificates of deposit. Other income includes income we receive for providing salt water disposal and natural gas transportation services to other working interest participants in wells that we operate.

Interest expense. Interest expense includes interest paid to our lenders as a result of borrowings under our revolving credit agreement. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under the credit agreement, and as a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. In addition, we include any amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees as interest expense.

 

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Total income tax provision (benefit). Total income tax provision (benefit) includes the net current and deferred portions of our estimated income tax liabilities. We file a United States federal income tax return and state tax returns in those states where we conduct oil and natural gas operations. The current portion of our income tax provision (benefit) reflects actual income tax payments made or refunds received by us as a result of filing these income tax returns. The deferred portion of our income tax provision is the result of temporary timing differences between the financial statement carrying values and the tax bases of our assets and liabilities.

The following table summarizes our operating expenses and other income (expense) for the periods indicated:

 

     Year Ended
December 31,
    Nine Months Ended
September 30,
 
     2010     2009     2008     2011     2010  
                       (Unaudited)     (Unaudited)  
(In thousands, except expenses per Mcfe)       

Expenses:

          

Production taxes and marketing

   $ 1,982      $ 1,077      $ 1,639      $ 4,801      $ 1,235   

Lease operating

     5,284        4,725        4,667        5,639        3,801   

Depletion, depreciation and amortization

     15,596        10,743        12,127        22,578        10,931   

Accretion of asset retirement obligations

     155        137        91        158        107   

Full-cost ceiling impairment

            25,244        22,195        35,673          

General and administrative

     9,702        7,115        8,252        9,395        6,793   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

     32,719        49,041        48,972        78,244        22,867   

Operating income (loss)

     9,761        (24,752     (16,061     (20,464     11,116   

Other income (expense):

          

Net gain (loss) on asset sales and inventory impairment

     (224     (379     136,978                 

Interest and other income

     364        781        2,984        248        300   

Interest expense

     (3                   (461       
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

     137        402        139,962        (213     300   

Income (loss) before income taxes

     9,898        (24,350     123,901        (20,677     11,416   

Total income tax provision (benefit)

     3,521        (9,925     20,023        (6,952     4,043   

Net income (loss)

   $ 6,377      $ (14,425   $ 103,878      $ (13,725   $ 7,373   

Expenses per Mcfe:

          

Production taxes and marketing

   $ 0.23      $ 0.22      $ 0.50      $ 0.41      $ 0.21   

Lease operating

   $ 0.61      $ 0.94      $ 1.41      $ 0.49      $ 0.63   

Depletion, depreciation and amortization

   $ 1.81      $ 2.15      $ 3.67      $ 1.95      $ 1.82   

General and administrative

   $ 1.13      $ 1.42      $ 2.50      $ 0.81      $ 1.13   

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Production taxes and marketing. Our production taxes and marketing expenses increased by $3.6 million to $4.8 million, or an increase of approximately 289% for the nine months ended September 30, 2011, as compared to the nine months ended September 30, 2010. The increase in our production taxes and marketing expenses reflects the increases in both our oil and natural gas production and revenues by 93% and 107%, respectively, during the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. The majority of this increase was due to higher marketing, transportation and compression charges on non-operated Haynesville shale production in the first nine months of 2011 as compared to the same period in 2010. Some of this increase was also due to recently completed Haynesville shale wells, several of which were turned to sales or produced their first significant production volumes during the first nine months of 2011. Although we or our outside operating partners have applied for exemptions from initial production taxes on these recently completed Haynesville shale wells, and although we expect these applications will be approved by the state of Louisiana, some of these wells had not yet been approved for production tax exemptions at September 30, 2011. Thus, we have paid and/or accrued for

 

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the associated production taxes on these wells during the first nine months of 2011, although we expect these production taxes will be refunded to us in future periods. We will adjust our production taxes and marketing expenses accordingly when and if these production tax exemptions are approved. The remainder of the increase in production taxes and marketing expenses for the nine months ended September 30, 2011 was due to production taxes paid on initial production from our first two operated Eagle Ford shale wells in south Texas.

Lease operating expenses. Our lease operating expenses increased by $1.8 million to $5.6 million, or an increase of about 48%, for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. During these respective periods, however, our oil and natural gas production increased 93% from 6.0 Bcfe to 11.6 Bcfe. As a result, our lease operating expenses per unit of production decreased by 22% to $0.49 per Mcfe for the nine months ended September 30, 2011 as compared to $0.63 per Mcfe for the nine months ended September 30, 2010. During the first nine months of 2011, the percentage of our production attributed to the Haynesville shale continued to increase. The unit lease operating costs associated with the Haynesville production are much less than those associated with our Cotton Valley natural gas production, primarily due to the greater salt water disposal costs associated with the Cotton Valley production.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by $11.6 million to $22.6 million, or an increase of about 107%, for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. The increase in our depletion, depreciation and amortization expenses was due primarily to an increase of approximately 93% in our oil and natural gas production from 6.0 Bcfe to 11.6 Bcfe during the respective time periods. A portion of this increase was also due to a 7% increase in our depletion, depreciation and amortization expenses on a unit-of-production basis from $1.82 per Mcfe for the nine months ended September 30, 2010 to $1.95 per Mcfe for the nine months ended September 30, 2011. This increase reflects increases in drilling and completion costs for wells drilled to the Haynesville shale during the past year. This increase was also due, in part, to higher finding and development costs on a per Mcfe basis associated with our initial wells drilled and completed in the Eagle Ford shale.

Accretion of asset retirement obligations. Our accretion of asset retirement obligations expenses increased by approximately $51,000 to approximately $158,000, or an increase of about 48%, for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. The increase in our accretion of asset retirement obligations was due primarily to the addition of new wells through our drilling of operated wells and our participation in the drilling of non-operated wells, although, on the whole, this item is an insignificant component of our overall expenses.

Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas properties on the balance sheet resulting from the full-cost ceiling limitation was recorded at September 30, 2010. At March 31, 2011, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $23.0 million. As a result, we recorded an impairment charge of $35.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $12.7 million, which is also reflected in our expenses for the nine months ended September 30, 2011.

General and administrative. Our general and administrative expenses increased by $2.6 million to $9.4 million, or an increase of about 38%, for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. The increase in our general and administrative expenses was due

 

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primarily to increased cash and non-cash compensation expenses and increased accounting and legal expenses for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. As a result of our increased oil and natural gas production, however, our general and administrative expenses decreased by 28% on a unit-of-production basis to $0.81 per Mcfe for the nine months ended September 30, 2011 as compared to $1.13 per Mcfe for the nine months ended September 30, 2010.

Net gain (loss) on asset sales and inventory impairment. We did not incur gains or losses on asset sales and inventory impairment during the nine months ended September 30, 2011 or during the nine months ended September 30, 2010.

Interest expense. At September 30, 2011, we had borrowed $85.0 million under our credit agreement, including a term loan of $25.0 million, to finance a portion of our working capital requirements and capital expenditures and had incurred total interest expense of approximately $1.2 million. We capitalized $756,000 of our interest expense on certain qualifying projects for the nine months ended September 30, 2011 and expensed the remaining $461,000 to operations. At September 30, 2011, the interest rate on the term loan was approximately 5.3% and the interest rate on the other outstanding borrowings was approximately 2.2%. We had no borrowings under the credit agreement at September 30, 2010 and, as a result, we incurred no interest expense for the nine months ended September 30, 2010.

Interest and other income. Our interest and other income decreased by approximately $52,000 to approximately $248,000, or a decrease of about 17%, for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. The decrease in our interest and other income was due primarily to a significant decrease in the average balances of our cash and cash equivalents and certificates of deposit on which we received interest income between the two periods. Our cash and cash equivalents and certificates of deposit decreased to approximately $9.9 million at September 30, 2011 from approximately $46.0 million at September 30, 2010, as we used cash to acquire additional leasehold acreage in the Eagle Ford shale play in south Texas and in the core area of the Haynesville shale play in northwest Louisiana and to fund our operated and non-operated drilling and completion activities in both areas.

Total income tax provision (benefit). We recorded a total income tax benefit of approximately $7.0 million for the nine months ended September 30, 2011 as compared to a total income tax provision of approximately $4.0 million for the nine months ended September 30, 2010. The total income tax benefit for the nine months ended September 30, 2011 reflected deferred income taxes almost entirely, with the exception of a state of Louisiana income tax refund of approximately $46,000 recorded during this period. At March 31, 2011, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $23.0 million. As a result, we recorded an impairment charge of $35.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $12.7 million. This deferred income tax credit exceeded our deferred tax liabilities at March 31, 2011, and as a result, we reduced our net deferred tax liabilities by $6.9 million and established a net valuation allowance due to uncertainties regarding the future realization of our deferred tax assets. We retained a net valuation allowance in the amount of approximately $0.8 million at September 30, 2011. We will continue to assess the valuation allowance on a periodic basis and to the extent we determine that the allowance is no longer required, the tax benefit of the remaining deferred tax assets will be recognized in the future. The total income tax provision for the nine months ended September 30, 2010 included a deferred income tax provision of approximately $5.4 million and a current income tax benefit of approximately $1.4 million, which was attributable to a refund of U.S. federal income taxes received by us. For the nine months ended September 30, 2010, the deferred income tax provision was consistent with our

 

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income before income taxes, which included approximately $5.8 million in unrealized hedging gains. We had a net loss for the nine months ended September 30, 2011, and our effective tax rate for the nine months ended September 30, 2010 was 35.42%.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Production taxes and marketing. Our production taxes and marketing expenses increased by $0.9 million to $2.0 million, or an increase of about 84%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increase in our production taxes and marketing expenses was due primarily to the increase in our oil and natural gas revenues from $19.0 million to $34.0 million, or an increase of about 79%, during the respective time periods. On a unit-of-production basis, our production taxes and marketing expenses remained relatively constant year-over-year, increasing to $0.23 per Mcfe for the year ended December 31, 2010 from $0.22 per Mcfe for the year ended December 31, 2009.

Lease operating expenses. Our lease operating expenses increased by $0.6 million to $5.3 million, or an increase of about 12%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. During these respective periods, however, our oil and natural gas production increased 72% to 8.6 Bcfe from 5.0 Bcfe. As a result, our lease operating expenses per unit of production decreased by 35% to $0.61 per Mcfe for the year ended December 31, 2010 as compared to $0.94 per Mcfe for the year ended December 31, 2009. In 2010, the percentage of our production attributed to the Haynesville shale continued to increase. The unit lease operating costs associated with the Haynesville production are much less than those associated with our Cotton Valley natural gas production, primarily due to the greater salt water disposal costs associated with the Cotton Valley production.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by $4.9 million to $15.6 million, or an increase of about 45%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increase in our depletion, depreciation and amortization expenses was due primarily to the increase in our natural gas production to 8.6 Bcfe from 5.0 Bcfe during the respective time periods. The finding and development costs associated with our Haynesville shale reserves have been less than finding and development costs associated with our reserves producing from the Cotton Valley and other formations. As a result, our depletion, depreciation and amortization expenses on a unit-of-production basis have continued to decrease as our Haynesville production has increased; these expenses decreased to $1.81 per Mcfe during the year ended December 31, 2010 from $2.15 per Mcfe during the year ended December 31, 2009.

Accretion of asset retirement obligations. Our accretion of asset retirement obligations expenses increased by approximately $18,000 to approximately $155,000, or an increase of about 13%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increase in our accretion of asset retirement obligations was due primarily to the addition of new wells through our drilling of operated wells and our participation in the drilling of non-operated wells.

Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas properties on the balance sheet resulting from the full-cost ceiling limitation was recorded at December 31, 2010. At December 31, 2009, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $16.3 million. As a result, we recorded an impairment charge of $25.2 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $8.9 million. A corresponding charge of $25.2 million was also recorded to the consolidated statement of operations for the year ended December 31, 2009.

 

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General and administrative. Our general and administrative expenses increased by $2.6 million to $9.7 million, or an increase of about 36%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. Approximately $1.0 million of this increase was due to legal and other due diligence fees resulting from an unsuccessful effort to acquire oil and natural gas producing properties and associated acreage. The remainder of the increase was due primarily to increased compensation expenses resulting from both increased salaries and retention and performance bonuses paid to certain employees during the year ended December 31, 2010. As a result of our increased oil and natural gas production, however, our general and administrative expenses decreased by 20% on a unit-of-production basis to $1.13 per Mcfe for the year ended December 31, 2010 as compared to $1.42 per Mcfe for the year ended December 31, 2009.

Net gain (loss) on asset sales and inventory impairment. During the year ended December 31, 2010, we wrote off the Boise South Pipeline asset in Orange County, Texas and recognized a net loss of $173,690. We also recognized an impairment of $50,000 to some of our equipment held in inventory following a determination that the market value of the equipment, consisting primarily of drilling rig parts, was less than the cost. During the year ended December 31, 2009, we recognized impairments to these drilling rig parts and tubular goods held in inventory and sold rod parts held in inventory, recognizing a net loss of $0.4 million.

Interest expense. In December 2010, we borrowed $25.0 million under our revolving credit agreement to finance a portion of our working capital requirements and capital expenditures. At December 31, 2010, the interest rate on the outstanding borrowings was approximately 1.6%. We had no borrowings under the credit agreement in 2009, and as a result, we incurred no interest expense for the year ended December 31, 2009.

Interest and other income. Our interest and other income decreased by approximately $0.4 million to approximately $0.4 million, or a decrease of about 53%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The decrease in our interest and other income was due primarily to a decrease in the average balances of our cash and cash equivalents and certificates of deposit on which we receive interest income during the year ended December 31, 2010 as compared to the year ended December 31, 2009. Our cash and cash equivalents and certificates of deposit decreased to $23.4 million at December 31, 2010 from $119.9 million at December 31, 2009, as we used cash during this period primarily to acquire additional leasehold acreage in the Eagle Ford shale play in south Texas and in the core area of the Haynesville shale play in northwest Louisiana and to fund our operated and non-operated drilling and completion activities in both areas.

Total income tax provision (benefit). We recorded a total income tax provision of approximately $3.5 million for the year ended December 31, 2010 as compared to a total income tax benefit of approximately $9.9 million recorded for the year ended December 31, 2009. For the year ended December 31, 2010, we recorded a current income tax benefit of approximately $1.4 million, which was attributable to a refund of U.S federal income taxes received by us, and we also recorded a deferred income tax provision of $4.9 million consistent with the increase in our income before income taxes for that year. For the year ended December 31, 2009, we recorded a current income tax benefit of approximately $2.3 million, primarily attributable to a net refund of U.S. federal income taxes and a refund of income taxes from the state of Louisiana. We also recorded a deferred income tax benefit of approximately $7.6 million, primarily attributable to the full-cost ceiling impairment recorded in 2009. Our effective tax rate for the year ended December 31, 2010 was 35.57%, and we had a net loss for the year ended December 31, 2009.

 

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Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Production taxes and marketing. Our production taxes and marketing expenses decreased approximately $0.6 million to $1.1 million, or a decrease of about 34%, during the year ended December 31, 2009 as compared to the year ended December 31, 2008. The decrease in our production taxes and marketing expenses was due primarily to a decrease of about 38% in our oil and natural gas revenues to $19.0 million for the year ended December 31, 2009 from $30.6 million for the year ended December 31, 2008. Because our production increased 51% from 3.3 Bcfe to 5.0 Bcfe during these respective periods, our production taxes and marketing expenses on a unit-of-production basis decreased to $0.22 per Mcfe during the year ended December 31, 2009 from $0.50 per Mcfe for the year ended December 31, 2008.

Lease operating expenses. Our lease operating expenses increased approximately $58,000 to $4.7 million, or an increase of about 1%, during the year ended December 31, 2009 as compared to the year ended December 31, 2008. During these respective periods, however, our production increased 51%, from 3.3 Bcfe to 5.0 Bcfe. We began producing natural gas from the Haynesville shale in June 2009 and additional Haynesville wells began producing with corresponding sales during the latter part of 2009. Despite this production growth in 2009, our lease operating expenses increased only slightly due to the fact that the unit lease operating costs associated with the Haynesville production were much less than those associated with the Cotton Valley production, which made up the majority of our production during 2008. This is primarily due to the greater salt water disposal costs associated with the Cotton Valley production. As a result, our unit lease operating costs decreased to $0.94 per Mcfe during the year ended December 31, 2009 from $1.41 per Mcfe during the year ended December 31, 2008, or a decrease of about 33%.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses decreased $1.4 million to $10.7 million, or a decrease of about 11%, during the year ended December 31, 2009 as compared to the year ended December 31, 2008. Our depletion, depreciation and amortization expenses decreased despite the fact that our production grew 51% from 3.3 Bcfe to 5.0 Bcfe during these respective periods. This decrease was due to the fact that the finding and development costs associated with our Haynesville shale production have been less than the finding and development costs associated with our production from the Cotton Valley and other formations. As a result, our depletion, depreciation and amortization expenses on a unit-of-production basis decreased to $2.15 per Mcfe for the year ended December 31, 2009 from $3.67 per Mcfe for the year ended December 31, 2008.

Accretion of asset retirement obligations. Our accretion of asset retirement obligations expenses increased approximately $46,000 to $137,000, or an increase of about 51%, during the year ended December 31, 2009 as compared to the year ended December 31, 2008. The increase in our accretion of asset retirement obligations was due primarily to the addition of new wells through our drilling of operated wells and our participation in the drilling of non-operated wells.

Full-cost ceiling impairment. At December 31, 2009, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $16.3 million. As a result, we recorded an impairment charge of $25.2 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $8.9 million. A corresponding charge of $25.2 million was also recorded to the consolidated statement of operations for the year ended December 31, 2009. At December 31, 2008, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $14.3 million. As a result, we recorded an impairment charge of $22.2 million to the net capitalized costs of our oil and natural gas properties and a deferred

 

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income tax credit of $7.9 million. A corresponding charge of $22.2 million was also recorded in the consolidated statement of operations for the year ended December 31, 2008.

General and administrative. Our general and administrative expenses decreased by $1.1 million to $7.1 million, or a decrease of about 14%, for the year ended December 31, 2009 as compared to the year ended December 31, 2008. The decrease in our general and administrative expenses was due primarily to a decrease in compensation expenses between the respective periods. In July 2008, we paid a special cash performance bonus of approximately $1.7 million to eligible employees in recognition of the significant increase in the value of our assets resulting from the sale of a portion of our Haynesville shale exploration and development rights in northwest Louisiana. We did not make any such extraordinary cash bonus payments to our employees during the year ended December 31, 2009; however, the decrease in bonus compensation in 2009 as compared to 2008 was offset to some degree by additional compensation expense associated with the hiring of new staff and the general increase in the costs to conduct our business during the year ended December 31, 2009. As a result of our increased oil and natural gas production, however, our general and administrative expenses decreased by 43% on a unit-of-production basis to $1.42 per Mcfe for the year ended December 31, 2009 as compared to $2.50 per Mcfe for the year ended December 31, 2008.

Net gain (loss) on asset sales and inventory impairment. Our net gain (loss) on asset sales and inventory impairment decreased by $137.4 million to a net loss of approximately $0.4 million for the year ended December 31, 2009 as compared to a net gain of $137.0 million for the year ended December 31, 2008. During the year ended December 31, 2009, we recognized impairments to drilling rig parts and tubular goods held in inventory and sold rod parts held in inventory, recognizing a net loss of $0.4 million. During the year ended December 31, 2008, we sold a portion of our Haynesville shale exploration and development rights in northwest Louisiana to a subsidiary of Chesapeake Energy Corporation and recognized a gain of $137.0 million on the sale. We also recognized a loss of about $44,000 on the sale of tubular goods held in inventory during 2008.

Interest expense. We had no borrowings under our credit agreement in 2009 or 2008. As a result, we had no interest expense for the years ended December 31, 2009 and 2008.

Interest and other income. Our interest and other income expenses decreased by $2.2 million to $0.8 million, or a decrease of about 74%, for the year ended December 31, 2009 as compared to the year ended December 31, 2008. The decrease in our interest and other income expenses was due primarily to a decrease in the average balances of our cash and cash equivalents and certificates of deposit on which we receive interest income during the respective periods. Our cash and cash equivalents and certificates of deposit decreased to $119.9 million at December 31, 2009 from $171.6 million at December 31, 2008, as we used cash during this period primarily to acquire additional leasehold acreage in the core area of the Haynesville shale play in northwest Louisiana and to fund our operated and non-operated drilling and completion activities.

Total income tax provision (benefit). We recorded a total income tax benefit of approximately $9.9 million for the year ended December 31, 2009 as compared to a total income tax provision of approximately $20.0 million for the year ended December 31, 2008. For the year ended December 31, 2009, we recorded a current income tax benefit of approximately $2.3 million, primarily attributable to a net refund of U.S. federal income taxes and a refund of income taxes from the state of Louisiana. We also recorded a deferred income tax benefit of approximately $7.6 million, primarily attributable to the full-cost ceiling impairment recorded in 2009. For the year ended December 31, 2008, we recorded a current income tax provision of approximately $10.4 million which reflects the payment of $9.4 million in U.S. federal alternative minimum

 

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tax and approximately $1.0 million in income tax to the state of Louisiana. The alternative minimum tax payment resulted from exhausting our alternative minimum tax net operating loss due to the gain realized from the sale of certain of our Haynesville shale assets. See “Business — Other Significant Prior Events.” We also recorded a deferred income tax provision of approximately $9.6 million, reflecting both the large increase in our income before income taxes for the year, partially offset by the deferred income tax benefit attributable to the full-cost ceiling impairment recorded in 2008, and by the reversal of a previously established valuation allowance of approximately $24.7 million. We had a net loss for the year ended December 31, 2009, and our effective tax rate for the year ended December 31, 2008 was 16.16%.

Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from private investors, our cash flows from operations, borrowings under our credit agreement and the proceeds from a significant sale of a portion of our assets in 2008. See “Business — Other Significant Prior Events.” Our primary use of capital has been for the acquisition, exploration and development of oil and natural gas properties. We continually evaluate potential capital sources, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital. At September 30, 2011, we had cash and certificates of deposits totaling approximately $9.9 million.

In December 2011, we amended and restated our senior secured revolving credit agreement for which Comerica Bank serves as administrative agent. This amendment increased the maximum facility amount from $150 million to $400 million. Borrowings are limited to the lesser of $400 million or the borrowing base. At January 27, 2012, the borrowing base was $125 million, and we had $123.0 million of outstanding indebtedness. There were $1.3 million in outstanding letters of credit at September 30, 2011. Following this offering and after application of the net proceeds, our borrowing base will be $100 million until a subsequent redetermination, which we expect will be done following the completion of our December 31, 2011 reserves report. The new amended credit agreement matures in December 2016. At January 27, 2012, all borrowings under our credit agreement bore interest at a variable rate of 3.25% plus a Eurodollar-based rate per annum, which equated to approximately 3.5% per annum.

We previously entered into the credit agreement in March 2008 and amended and restated it for the first time in May 2011. At September 30, 2011, the agreement provided for a borrowing base of $80.0 million and our outstanding revolving borrowings under the credit agreement bore interest at the rate of 2.2%. In addition to our revolving borrowings under the credit agreement, in May 2011, we borrowed $25 million in a term loan pursuant to the credit agreement. The term loan was due and payable on December 31, 2011, and there was no penalty for prepayment. The term loan bore interest at an annual rate of 5% plus a Eurodollar-based rate, which equated to approximately 5.3% at September 30, 2011. This term loan was refinanced by revolving borrowings under the amended and restated credit agreement in December 2011. For more information regarding our amended and restated credit agreement, see “— Credit Agreement.”

We actively review acquisition opportunities on an ongoing basis. While we believe the net proceeds we receive from this offering, together with our cash flows and future potential borrowings under our credit agreement, will be adequate to fund our capital expenditure requirements and any acquisitions of interests and acreage for 2012, funding for future acquisitions of interests and acreage or our future capital expenditure requirements for 2013 and subsequent years may require additional sources of financing, which may not be available. As a result of our anticipated increases in production and reserves, we expect to have

 

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a sufficient increase in our cash flows from operations during the year ending December 31, 2012, as compared to our cash flows from operations in prior periods, as well as a sufficient increase in the borrowing base under our credit agreement to help fund our 2012 capital expenditure budget. A majority of our anticipated increase in cash flows during the year ending December 31, 2012 is expected to come from our exploration activities on unproved properties at September 30, 2011 in the Eagle Ford shale play assuming such exploration activities are successful. These anticipated increases in our cash flows from operations are based upon current oil and natural gas prices and the hedges we currently have in place. If our exploration activities result in less cash flows than anticipated, we may seek additional sources of capital, including through borrowings under our credit agreement (assuming availability under our borrowing base) or from the issuance of additional equity or debt securities. In addition, we may modify our planned capital expenditure budget for 2012 accordingly. Exploration activities are subject to a number of risks and uncertainties that could impact our ability to sufficiently increase our reserves, cash flows from operations and borrowing base under our credit agreement. See “Risk Factors — Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows From Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth” and “— Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties That Could Adversely Affect Our Business.” We anticipate that we may need to access future borrowings under our credit agreement within 30 days following completion of this offering to fund a portion of our 2012 capital expenditure requirements in excess of amounts available from our cash flows and the net proceeds of this offering. See “Use of Proceeds.”

Our cash flows for the years ended December 31, 2010, 2009 and 2008 and the nine months ended September 30, 2011 and 2010, are presented below:

 

     Year Ended
December 31,
     Nine Months Ended
September 30,
 
     2010     2009     2008      2011     2010  
(In thousands)                       (Unaudited)     (Unaudited)  

Net cash provided by operating activities

   $ 27,273      $ 1,791      $ 25,851       $ 34,443      $ 21,390   

Net cash provided by (used in) investing activities

     (147,334     (49,415     115,481         (107,772     (78,718

Net cash provided by (used in) financing activities

     36,891        1,086        419         60,037        (8,284
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Net change in cash and cash equivalents

   $ (83,170   $ (46,538   $ 141,751       $ (13,292   $ (65,612

Cash Flows Provided by Operating Activities

Net cash provided by operating activities increased by $13.0 million to $34.4 million for the nine months ended September 30, 2011 as compared to net cash provided by operating activities of $21.4 million for the nine months ended September 30, 2010. Net cash provided by oil and natural gas operations increased significantly to $37.1 million for the nine months ended September 30, 2011 from $18.5 million for the nine months ended September 30, 2010. This increase reflects primarily the 93% increase in our oil and natural gas production to 11.6 Bcfe from 6.0 Bcfe between the respective periods. This increase in cash flows provided by oil and natural gas operations was offset partially by changes in our operating assets and liabilities totaling approximately $5.6 million between September 30, 2010 and September 30, 2011. Our accounts payable and accrued liabilities increased to approximately $21.4 million at September 30, 2011 from approximately $15.2 million at September 30, 2010 due to our increased operating activity in south Texas. Our accounts receivable increased to $14.1 million at September 30, 2011 as compared to $7.5 million at September 30, 2010 due primarily to the increase in our oil and natural gas production and associated revenues.

 

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Net cash provided by operating activities increased by $25.5 million to $27.3 million for the year ended December 31, 2010 as compared to net cash provided by operating activities of $1.8 million for the year ended December 31, 2009. The increase in cash flows provided by operations reflects an increase in our production to 8.6 Bcfe from 5.0 Bcfe and an increase in the average prices we received for oil and natural gas production for the year ended December 31, 2010 as compared to the year ended December 31, 2009. Our accounts payable and accrued liabilities were approximately $26.8 million at December 31, 2010 as a result of operated horizontal wells that we were drilling and/or completing in the Haynesville and Eagle Ford shale plays and in the Cotton Valley formation during the fourth quarter of 2010. Our accounts payable and accrued liabilities were $7.3 million at December 31, 2009 as we were drilling and completing only one operated horizontal Haynesville shale well at that time.

Net cash provided by operating activities decreased by $24.1 million to $1.8 million for the year ended December 31, 2009 from $25.9 million for the year ended December 31, 2008. Although our production increased to 5.0 Bcfe for the year ended December 31, 2009 from 3.3 Bcfe for the year ended December 31, 2008, the average prices we received for oil and natural gas declined sharply between the respective periods. Our accounts payable and accrued liabilities were approximately $7.3 million at December 31, 2009 as we were drilling and/or completing only one operated horizontal Haynesville shale well at that time. Our accounts payable and accrued liabilities were approximately $25.2 million at December 31, 2008 as we were drilling and/or completing both operated vertical Cotton Valley wells and our first operated horizontal wells in the Haynesville shale play at that time.

Our operating cash flows are sensitive to a number of variables, including changes in our production and volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “— Quantitative and Qualitative Disclosures About Market Risk” below. See also “Risk Factors — Our success is dependent on the prices of oil and natural gas. Low oil or natural gas prices and the substantial volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.”

Cash Flows Provided by (Used in) Investing Activities

Net cash used in investing activities increased by $29.1 million to $107.8 million for the nine months ended September 30, 2011 from $78.7 million for the nine months ended September 30, 2010. This increase in net cash used in investing activities reflected primarily an increase of $18.7 million in our oil and natural gas properties capital expenditures for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. The increased oil and natural gas properties capital expenditures for the nine months ended September 30, 2011 were primarily due to increased expenditures associated with our operated and non-operated drilling and completion activities in the Eagle Ford and Haynesville plays and our acreage acquisition in Karnes, DeWitt, Wilson and Gonzales Counties, Texas, as compared to the nine months ended September 30, 2010.

Net cash used in investing activities increased by $97.9 million to $147.3 million for the year ended December 31, 2010 from $49.4 million for the year ended December 31, 2009. This increase in net cash used in investing activities reflects primarily an increase of $104.8 million in our oil and natural gas properties capital expenditures for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increased oil and natural gas properties capital expenditures for the year ended December 31, 2010 are due to the acquisition of leasehold acreage in the Eagle Ford shale play and the

 

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acquisition of additional leasehold acreage in the Haynesville shale play, as well as expenditures associated with our operated and non-operated drilling and completion activities in both plays, as compared to the year ended December 31, 2009.

Net cash used in investing activities was $49.4 million for the year ended December 31, 2009 as compared to net cash provided by investing activities of $115.5 million for the year ended December 31, 2008. This decrease of $164.9 million in net cash provided by investing activities between the respective periods reflects primarily the proceeds received from the sale of a portion of our Haynesville rights in northwest Louisiana to a subsidiary of Chesapeake Energy Corporation in 2008. In addition, our oil and natural gas properties capital expenditures decreased by $49.9 million between the two periods owing to a decrease in our operated drilling activity and related capital expenditures in 2009.

Expenditures for the acquisition, exploration and development of oil and natural gas properties are the primary use of our capital resources. We anticipate investing $313.0 million in capital for acquisition, exploration and development activities in 2012 as follows:

 

     Amount
(in  millions)
 

Exploration and development drilling and associated infrastructure

   $ 284.5   

Leasehold acquisition

     24.0   

Other capital expenditures, 2-D and 3-D seismic data and recompletions of existing wells

     4.5   
  

 

 

 

Total

   $ 313.0   
  

 

 

 

For further information regarding our anticipated capital expenditure budget in 2012, see “Business—Overview.”

Our 2012 capital expenditures may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil or natural gas prices decline or costs increase significantly, we could defer a significant portion of our anticipated capital expenditures until later periods to conserve cash or to focus on those projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations and other factors both within and outside our control.

Cash Flows Provided by (Used in) Financing Activities

Net cash provided by financing activities was $60.0 million for the nine months ended September 30, 2011 as compared to net cash used in financing activities of $8.3 million for the nine months ended September 30, 2010. The net cash provided by financing activities for the nine months ended September 30, 2011 was due almost entirely to additional borrowings of $60.0 million under our credit agreement to fund our working capital requirements as well as our acquisition of acreage prospective for the Eagle Ford shale play in Karnes, DeWitt, Wilson and Gonzales Counties, Texas. In addition, in January 2011, we sold 53,772 shares of our Class A common stock in a private placement and received net proceeds of approximately $0.6 million. The net cash used in financing activities of $8.3 million for the nine months ended September 30, 2010 reflected primarily our repurchase of 1,000,000 shares of Class A common stock in April 2010 at $9.00 per share for a total of $9.0 million.

 

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Net cash provided by financing activities was $36.9 million for the year ended December 31, 2010 as compared to net cash provided by financing activities of $1.1 million for the year ended December 31, 2009. For the year ended December 31, 2010, the most significant financing activities occurred in the fourth quarter of 2010. During that time, we sold approximately 1.9 million shares of our Class A common stock in a private placement and received net proceeds of approximately $21.0 million, and we borrowed $25.0 million under our credit agreement. In addition, in April 2010, we repurchased 1,000,000 shares of Class A common stock from five shareholders, all advised by Wellington Management Company, for a total of $9.0 million. We also received proceeds of approximately $2.0 million from the periodic exercise of stock options for the year ended December 31, 2010. For the year ended December 31, 2009, the most significant financing activities occurred in April 2009 when we repurchased approximately 5.4 million shares of Class A common stock from Gandhara Capital, one of our largest shareholders at the time, for a total of $27.1 million and in May through September 2009 when we sold approximately 5.0 million shares of Class A common stock in a private placement and received net proceeds of approximately $28.0 million. We also received proceeds of approximately $1.3 million from the periodic exercise of stock options for the year ended December 31, 2009.

Net cash provided by financing activities was $1.1 million for the year ended December 31, 2009 as compared to $0.4 million for the year ended December 31, 2008. For the year ended December 31, 2009, the most significant financing activities occurred in April 2009 when we repurchased approximately 5.4 million shares of Class A common stock from Gandhara Capital, one of our largest shareholders at the time, at $5.00 per share for a total of $27.1 million and in May through September 2009 when we sold approximately 5.0 million shares of Class A common stock in a private placement and received net proceeds of approximately $28.0 million. We also received proceeds of approximately $1.3 million from the periodic exercise of stock options for the year ended December 31, 2009. For the year ended December 31, 2008, the most significant financing activities were the periodic exercise of stock options for which we received aggregate net proceeds of approximately $1.0 million.

Credit Agreement

In December 2011, we amended and restated our senior secured revolving credit agreement for which Comerica Bank serves as administrative agent. Among other things, this amendment increased the size of the facility and extended the term until December 2016. MRC Energy Company is the borrower under the new amended and restated credit agreement. Borrowings under the credit agreement are secured by mortgages on substantially all of our oil and natural gas properties and by the equity interests of all of MRC Energy Company’s wholly owned subsidiaries, which are also guarantors. In addition, all obligations under the credit agreement are guaranteed by Matador Resources Company, the parent corporation. Various commodity hedging agreements and interest rate agreements with one of the lenders under the credit agreement (or an affiliate thereof) are also secured by the collateral and guaranteed by the subsidiaries of MRC Energy Company.

The amount of the borrowings under our amended and restated credit agreement is limited to the lesser of $400.0 million or the borrowing base, which is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our existing and future acquired oil and gas reserves, but also on external factors, such as the lenders’ lending policies and the lenders’ estimates of future oil and natural gas prices, over which we have no control. At January 27, 2012, the borrowing base was $125.0 million. After repayment of the then outstanding borrowings under our credit agreement with the net proceeds of this offering, the borrowing base will be reduced to $100.0 million until any subsequent redetermination of the borrowing base under the agreement, which we expect will be done following the

 

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completion of our December 31, 2011 reserves report. Both Comerica Bank and we may each request an unscheduled redetermination of the borrowing base twice during the first year of the credit agreement and once between scheduled determination dates thereafter. In the event of a borrowing base increase, we are required to pay a fee to the lenders, which will be determined by Comerica Bank based on market conditions at the time of the borrowing base increase. Except as set forth in the following sentence, if the borrowing base were to be less than the outstanding borrowings under the credit agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months. If, however, our outstanding borrowings under the credit agreement exceed $100.0 million on the earlier of December 31, 2012, the second business day following receipt by us of the net cash proceeds from this offering, or the date on which we inform the lenders that the borrowing base is equal to $100.0 million, then we will be required to immediately repay such excess amount.

If we borrow funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the weighted average of rates used in overnight federal funds transactions with members of the Federal Reserve System plus 1.0%, (ii) the prime rate for Comerica Bank then in effect or (iii) a daily adjusted LIBOR rate plus 1.0% plus, in each case, an amount from 0.375% to 1.75% of such outstanding loan depending on the level of borrowings under the agreement. If we borrow funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the interest rate appearing on Page BBAM of the Bloomberg Financial Markets Information Service by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which Comerica Bank is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System), plus (ii) an amount from 1.375% to 2.75% of such outstanding loan depending on the level of borrowings under the agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by us. A facility fee of 0.375% to 0.50%, depending on the amounts borrowed, is also paid quarterly in arrears. We include this facility fee in our interest rate calculations and related disclosures.

Key financial covenants under the credit agreement require us to maintain (1) a minimum current ratio, which is defined as consolidated total current assets (including the unused availability under the credit agreement) divided by consolidated total current liabilities, of 1.0 or greater, and (2) a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.0 to 1.0 or less.

Subject to certain exceptions, our credit agreement contains various covenants that limit our, along with our subsidiaries’, ability to take certain actions, including, but not limited to, the following:

 

   

incur indebtedness or grant liens on any of our assets;

 

   

enter into commodity hedging agreements;

 

   

declare or pay dividends, distributions or redemptions;

 

   

merge or consolidate;

 

   

make any loans or investments;

 

   

engage in transactions with affiliates; and

 

   

engage in certain asset dispositions, including a sale of all or substantially all of our assets.

 

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If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Events of default include, but are not limited to, the following events:

 

   

failure to pay any principal or interest on the notes or any reimbursement obligation under any letter of credit when due or any fees or other amount within certain grace periods;

 

   

failure to perform or otherwise comply with the covenants and obligations in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;

 

   

bankruptcy or insolvency events involving us or our subsidiaries; and

 

   

a change of control, as defined in the credit agreement.

We had no borrowings under the credit agreement at December 31, 2009 and 2008. In December 2010, the credit agreement was amended to increase the borrowing base to $55.0 million. At December 31, 2010, we had $25.0 million of outstanding borrowings and $50,000 in letters of credit issued pursuant to the credit agreement. At December 31, 2010, all borrowings under the credit agreement were Eurodollar loans, and the interest rate on the outstanding borrowings was approximately 1.6%. We had an additional $325,000 in letters of credit secured by certificates of deposit at Comerica Bank at December 31, 2010.

We believe that we were in compliance with the terms of our credit agreement and with all our bank covenants at December 31, 2010, 2009 and 2008. We obtained a written extension from Comerica Bank until July 15, 2011 to comply with a covenant under the credit agreement requiring submission of audited financial statements within 120 days of the prior year end and the submission of quarterly financial statements within 45 days of the prior quarter end. We submitted both sets of financial statements to Comerica Bank prior to this deadline.

At September 30, 2011, the borrowing base available for revolving borrowings was $80.0 million, and we had $60.0 million in revolving borrowings outstanding under the credit agreement, approximately $1.3 million in outstanding letters of credit issued pursuant to the credit agreement and approximately $18.7 million available for additional borrowings. At September 30, 2011, our outstanding revolving borrowings bore interest at the rate of approximately 2.2%. Prior to the December 2011 amendment, the outstanding revolving borrowings under our credit agreement were scheduled to mature in March 2013.

In addition to our revolving borrowings under our credit agreement, in May 2011, we borrowed $25.0 million in a term loan pursuant to the credit agreement to help finance the acquisition of the Eagle Ford shale acreage from Orca ICI Development, JV in Karnes, DeWitt, Wilson and Gonzales Counties, Texas. The term loan was due and payable on December 31, 2011, and there was no penalty for prepayment. The term loan bore interest at an annual rate of 5% plus a Eurodollar-based rate, which equated to approximately 5.3% at September 30, 2011, and while any principal and interest under the term loan was outstanding, the revolving borrowings under the credit agreement bore interest at the maximum annual rate of 1.875% plus a Eurodollar-based rate which equated to approximately 2.2% at September 30, 2011. The term loan was refinanced by borrowings under the amended and restated credit agreement in December 2011. At January 27, 2012, the borrowing base available for revolving borrowings was $125.0 million, and we had $123.0 million in revolving borrowings outstanding under the credit agreement, excluding outstanding letters of credit. We intend to repay all then outstanding borrowings under our credit agreement with the net proceeds we receive from this offering. We anticipate that we may need to access future borrowings under our credit agreement within 30 days following completion of this offering to fund a portion of our 2012 capital expenditure requirements in excess of amounts available from our cash flows and the net proceeds of this offering.

 

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Obligations and Commitments

We had the following material contractual obligations and commitments at September 30, 2011 except as indicated:

 

     Payments Due by Period  
     Total      Less Than
1 Year
     1 -3 Years      3 -5 Years      More Than
5 Years
 
(in thousands)              

Contractual Obligations:

              

Revolving credit borrowings and term loan, including letters of credit(1)

   $  86,263       $ 26,263       $ 60,000       $       $   

Office lease

     6,243         144         1,150         1,186         3,763   

Non-operated drilling commitments(2)

     1,700         1,700                           

Drilling rig contracts(3)

     5,100         5,100                           

Geological and geophysical contracts(4)

     310         310                           

Employee bonuses

     1,240                 1,240                   

Asset retirement obligations

     4,305         332         461         957         2,555   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual cash obligations

   $ 105,161       $
33,849
  
   $ 62,851       $ 2,143       $ 6,318   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) At September 30, 2011, we had $60.0 million in revolving borrowings outstanding under our credit agreement, approximately $1.3 million in outstanding letters of credit issued pursuant to the credit agreement and $25.0 million outstanding under the term loan. The term loan was scheduled to mature on December 31, 2011, and our borrowings under our credit agreement were scheduled to mature in March 2013. All such amounts are now included as revolving borrowings under our credit agreement. These amounts do not include estimated interest on the obligations, because our revolving borrowings had short-term interest periods, and we are unable to determine what our borrowing costs may be in future periods. We incurred $38.0 million in additional borrowings in November and December 2011 and in January 2012 under our credit agreement to fund certain capital expenditures.

 

(2) At September 30, 2011, we had outstanding commitments to participate in the drilling and completion of various non-operated wells in the Haynesville shale play. Our working interest in these wells varies from 0.03% to 0.4%, and most of these wells were in progress at September 30, 2011. If all these wells are drilled and completed, we estimate that we will have a minimum outstanding aggregate capital commitment for our participation in these wells of approximately $1.7 million at September 30, 2011, which we expect to incur within the next 12 months.

 

(3) At September 30, 2011, we had entered into two drilling rig contracts to explore and develop our Eagle Ford acreage in south Texas. The first rig began drilling operations on our acreage in September 2011 and the second rig began drilling operations on our acreage in November 2011. Both contracts are for a term of six months. Should we elect to terminate both contracts and if the drilling contractor were unable to secure work for both rigs or if the drilling contractor were unable to secure work for both rigs at the same daily rates being charged to us prior to the end of their respective contract terms, we would incur termination obligations for either or both rigs. Our maximum outstanding aggregate capital commitment on these contracts was approximately $5.1 million as of September 30, 2011.

 

(4) Includes fees pending for two 3-D seismic acquisition projects across our Eagle Ford acreage in south Texas and for core analysis to be provided by a division of Core Laboratories, LP.

Critical accounting policies and estimates

We have outlined below certain accounting policies that are of particular importance to the presentation of our financial condition and results of operations and require the application of significant judgment or estimates by our management.

Basis of Presentation

The consolidated financial statements include the accounts of Matador Resources Company and its four wholly owned subsidiaries, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., MRC Permian Company and MRC Rockies Company, as well as the accounts of Longwood Gathering and Disposal Systems, LP (our consolidated financial statements for the years ended

 

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December 31, 2010, 2009 and 2008 reflect our organizational structure prior to the consummation of the holding company merger; see “Corporate Reorganization”). Our consolidated financial statements have been prepared in accordance with GAAP. Our operations are conducted in one segment, generally referred to as the exploration and production industry. All significant intercompany balances and transactions have been eliminated in consolidation.

Pursuant to the terms of the corporate reorganization that was completed on August 9, 2011, Matador Resources Company changed its corporate name to MRC Energy Company and Matador Holdco, Inc. changed its corporate name to Matador Resources Company. As a part of this reorganization, MRC Energy Company became a wholly owned subsidiary of Matador Resources Company. Our unaudited condensed consolidated financial statements at September 30, 2011 include the accounts of Matador Resources Company and its wholly owned subsidiary, MRC Energy Company, as well as the accounts of MRC Energy Company’s four wholly owned subsidiaries, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., MRC Permian Company and MRC Rockies Company, and the accounts of Longwood Gathering and Disposal Systems, LP.

Use of Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements. The preparation of our financial statements requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various 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. While we believe our estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates and assumptions used in preparation of our consolidated financial statements.

Our consolidated financial statements are based on a number of significant estimates. These include estimates of oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative financial instruments and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. Our oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors beyond our control, are prepared by our engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness by independent petroleum engineers, except for certain interim periods as noted.

Accounts Receivable

We sell our oil and natural gas production to various purchasers. Due to the nature of the markets for oil and natural gas, we do not believe that the loss of any one purchaser would significantly impact operations. In addition, we may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of our accounts receivable are due from either purchasers of oil and natural gas or participants in oil and natural gas wells for which we serve as the operator. Accounts

 

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receivable are due within 30 to 45 days of the production or billing date and are stated at amounts due from purchasers and industry partners.

We review our need for an allowance for doubtful accounts on a periodic basis, and determine the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate and the debtor’s ability to pay its obligations, among other things. We have no allowance for doubtful accounts related to our accounts receivable for any reporting period presented.

Property and Equipment

We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities.

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center ceiling, with any excess above the cost center ceiling charged to operations as a full-cost ceiling impairment. The cost center ceiling is defined as the sum of (a) the present value discounted at 10 percent of future net revenues of proved oil and natural gas reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) income tax effects related to differences between the book and tax basis of the properties involved. Future net revenues from proved non-producing and proved undeveloped reserves are reduced by the estimated costs of developing these reserves. The fair value of our derivative instruments is not included in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes.

The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent on the commodity prices used in these estimates. These estimates are determined in accordance with guidelines established by the SEC for estimating and reporting oil and natural gas reserves. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. In 2009, the SEC provided new guidelines for estimating and reporting oil and natural gas reserves. Under these new guidelines, the commodity prices used to estimate oil and natural gas reserves were changed from last-day-of-the-year prices to an unweighted, arithmetic average of first-day-of-the-month prices for the previous 12-month period.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment

 

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of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized.

Other property and equipment are stated at cost. Computer equipment, furniture, software and other equipment are depreciated over their useful life (five to seven years) using the straight-line method. Support equipment and facilities include the pipelines and salt water disposal systems owned by Longwood Gathering and Disposal Systems, LP and are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful life or the term of the lease.

Asset Retirement Obligations

We recognize the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or support equipment and facilities on the balance sheet. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statement of operations. In general, our future asset retirement obligations relate to future costs associated with plugging and abandonment of our oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in our estimate or if federal or state regulators enact new plugging and abandonment requirements. At the time of actual plugging and abandonment of our oil and natural gas wells, we include any gain or loss associated with the operation in the amortization base to the extent that the actual costs are different from the estimated liability.

Derivative Financial Instruments

From time to time, we use derivative financial instruments to hedge our exposure to commodity price risk associated with oil and natural gas prices. These instruments consist of put and call options in the form of costless collars. Our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We have elected not to apply hedge accounting for our existing derivative financial instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently in our consolidated statement of operations. The fair value of our derivative financial instruments is determined based on our counterparty’s valuation model which we verify for its reasonableness with an independent third party valuation using observable, market-corroborated inputs. Realized gains and realized losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in our consolidated statement of operations.

 

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Revenue Recognition

We follow the sales method of accounting for our oil and natural gas revenue, whereby we recognize revenue, net of royalties, on all oil or natural gas sold to purchasers regardless of whether the sales are proportionate to our ownership in the property. Under this method, revenue is recognized at the time the oil and natural gas are produced and sold, and we accrue for revenue earned but not yet received.

Stock-based Compensation

In 2003, our board of directors and shareholders approved the Matador Resources Company 2003 Stock and Incentive Plan, or the 2003 Plan. The persons eligible to receive awards under the 2003 Plan include our employees, directors, officers, consultants or advisors. The 2003 Plan is administered by our board of directors, which determines the number of options or restricted shares to be granted, the effective dates and terms of the grants, the option or restricted share price and the vesting period. In the absence of an established market for shares of our common stock as a private company, the board of directors determines the fair market value of our common stock for purposes of awards under the 2003 Plan. We typically use newly issued shares to satisfy option exercises or restricted share grants.

Our 2012 Long-Term Incentive Plan has been adopted, effective January 1, 2012. This plan permits the granting of long-term equity and cash incentive awards to our Named Executive Officers, key employees, consultants and non-employee directors. See “Compensation of Named Executive Officers — Long-Term Incentive Plan.”

Non-qualified stock option expense is recognized in our consolidated statement of operations on the date of the grant. Incentive stock options vest over four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Prior to November 22, 2010, all of our outstanding stock options were classified as equity instruments, with all stock-based compensation expense measured on the date of grant and recognized over the vesting period, if any. On November 22, 2010, we changed our method of accounting for outstanding stock options, reclassifying all outstanding stock options from equity to liability instruments. This change was made as a result of purchasing shares from certain of our employees to assist them in the exercise of outstanding options of our Class A common stock. As a result, at December 31, 2010 and at September 30, 2011, we measured and recognized the fair value of the liability associated with our outstanding stock options using an estimated fair value of our Class A common stock. On occasion, the board of directors grants restricted shares to eligible participants under the 2003 Plan. The fair value of these restricted stock awards are recognized based upon the fair value of our stock as determined by the board of direct