S-1 1 ds1.htm FORM S-1 Form S-1
Table of Contents
Index to Financial Statements

As filed with the Securities and Exchange Commission on August 12, 2011

Registration No. 333-

 

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Matador Resources Company

(Exact name of registrant as specified in its charter)

 

 

 

Texas   1311   27-4662601
(State or other jurisdiction of
incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification No.)

One Lincoln Centre

5400 LBJ Freeway, Suite 1500

Dallas, Texas 75240

(972) 371-5200

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

 

 

Joseph Wm. Foran

Chairman, President and Chief Executive Officer

Matador Resources Company

5400 LBJ Freeway, Suite 1500

Dallas, Texas 75240

(972) 371-5200

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

Copies to:

Janice V. Sharry
W. Bruce Newsome
Haynes and Boone, LLP
2323 Victory Avenue, Suite 700
Dallas, Texas 75219
(214) 651-5000
  Daryl B. Robertson
Douglas M. Berman
Hunton & Williams LLP
1445 Ross Avenue, Suite 3700
Dallas, Texas 75202
(214) 979-3000

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this registration statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 check the following box:    ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨

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

 

Large accelerated filer    ¨   Accelerated filer    ¨   Non-accelerated filer    x   Smaller reporting company    ¨
    (Do not check if a smaller reporting company)  

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to Be Registered

 

Amount to be

Registered(1)

 

Proposed Maximum

Offering

Price Per Share

 

Proposed Maximum

Aggregate

Offering Price(2)

 

Amount of

Registration

Fee

Common Stock, par value $0.01 per share

      $150,000,000   $17,415

 

 

(1) Includes  shares of common stock which may be issued on exercise of a 30-day option granted to the underwriters to cover over-allotments, if any.
(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(a) under the Securities Act of 1933, as amended.

 

 

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission acting pursuant to said Section 8(a), may determine.

 

 

 


Table of Contents
Index to Financial Statements

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and we are not soliciting offers to buy these securities in any state where the offer or sale is not permitted.

 

(Subject to completion, dated August 12, 2011)

PROSPECTUS Issued  , 2011

• Shares

LOGO

Matador Resources Company

Common Stock

 

 

Matador Resources Company is offering  shares of its common stock. This is our initial public offering, and no public market currently exists for our shares. We anticipate that the initial public offering price of our common stock will be between $ and $ per share.

We intend to apply to list our common stock on the New York Stock Exchange under the symbol “MTDR.”

Investing in our common stock involves risks. See “Risk Factors” beginning on page 20.

 

 

PRICE $ PER SHARE

 

 

 

            Underwriting         
     Price to      Discounts and      Proceeds to  
     Public      Commissions      Company  

Per Share

   $                 $                 $             

Total

   $                 $                 $             

We have granted the underwriters the right to purchase up to an additional  shares of common stock 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  , 2011.

 

 

 

RBC CAPITAL MARKETS

  CITIGROUP

, 2011


Table of Contents
Index to Financial Statements

LOGO


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

 

Prospectus Summary

     1   

Risk Factors

     20   

Cautionary Note Regarding Forward-Looking Statements

     47   

Use of Proceeds

     49   

Dividend Policy

     50   

Capitalization

     51   

Dilution

     52   

Selected Historical Consolidated and Other Financial Data

     53   

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

     55   

Business

     85   

Management

     122   

Compensation of Named Executive Officers

     135   

Certain Relationships and Related Party Transactions

     156   

Corporate Reorganization

     160   

Security Ownership of Management and Certain Beneficial Holders

     162   

Description of Capital Stock

     164   

Shares Eligible for Future Sale

     168   

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

     170   

Underwriters

     174   

Legal Matters

     180   

Experts

     180   

Where You Can Find More Information

     180   

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. We have not authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We 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 , 2011, 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 and Matador Holdco, Inc. and its subsidiaries after the completion of our corporate reorganization. In addition, 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.”

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 these plays 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 these 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 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 $46.5 million to provide a total initial capitalization of approximately $52.5 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

 

 

1


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Index to Financial Statements

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 194 wells through June 30, 2011, including 64 Haynesville and six Eagle Ford wells. From December 31, 2008 through March 31, 2011, we grew our estimated proved reserves from 20.0 Bcfe to 154.8 Bcfe. At March 31, 2011, 36% of our estimated proved reserves were proved developed reserves and 97% of our estimated proved reserves were natural gas. Also, we 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 several new wells that were recently completed, our daily production for May 2011 averaged approximately 49.1 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 $0.84 per Mcfe for the year ended December 31, 2010, or a decrease of approximately 55%.

The following table presents certain summary data for each of our operating areas at June 30, 2011 unless otherwise indicated:

 

            Producing
Wells
    

Total Identified

Drilling  Locations(1)

     Estimated Net Proved
Reserves
     Avg. Daily
Production
(MMcfe)(2)
 
     Net Acreage      Gross        Net          Gross          Net        Bcfe(3)      % Developed     

South Texas:

                       

Eagle Ford

     29,304         4.0         2.4         192.0         156.5         5.6         54.3         4.4   

Austin Chalk

     14,729                         16.0         16.0                           
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Area Total(4)

     29,304         4.0         2.4         208.0         172.5         5.6         54.3         4.4   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

NW Louisiana/E Texas:

                       

Haynesville

     14,624         64.0         10.3         557.0         106.2         131.9         27.1         36.8   

Cotton Valley(5)

     23,208         108.0         71.7         60.0         36.0         16.7         100.0         7.7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Area Total(6)

     25,673         172.0         82.0         617.0         142.2         148.6         35.3         44.5   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

SW Wyoming, NE Utah, SE Idaho

     135,862                                                           

SE New Mexico, West Texas

     19,852         13.0         5.7                         0.6         100.0         0.2   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     210,691         189.0         90.1         825.0         314.7         154.8         36.2         49.1   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(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.

 

(2) For May 2011.

 

(3) At March 31, 2011. These estimates were prepared by our engineering staff and audited by independent reservoir engineers, Netherland, Sewell & Associates, Inc.

 

(4) 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. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for south Texas. Includes acreage that we are producing from or that we believe to be prospective for these formations.

 

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

 

(6) 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. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for northwest Louisiana/east Texas. Includes acreage that we are producing from or that we believe to be prospective for these formations.

 

 

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Index to Financial Statements

At June 30, 2011, our properties included approximately 56,000 gross acres and 29,000 net acres in the Eagle Ford shale play in Atascosa, DeWitt, Dimmit, Karnes, LaSalle, Gonzales, Webb, Wilson and Zavala Counties in south Texas. We believe that almost 85% of our Eagle Ford acreage is prospective predominantly for oil or significant 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 August 2011, we completed our first four operated wells in this area (see “— Recent Developments”). We have identified 192 gross locations for potential future drilling in our Eagle Ford acreage.

In addition, at June 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, including almost 5,500 net acres in what we believe is the core area of the play. Almost 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 targets. In addition, we believe approximately 1,700 of these net acres are prospective for the Middle Bossier shale play. Our Haynesville acreage is approximately 10% developed and we have identified 557 gross locations for potential future drilling in our Haynesville acreage.

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 expect to resume operations on this initial test well in September 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 194 gross wells we have drilled or participated in drilling, we drilled approximately 49% of these wells as the operator. At July 31, 2011, we were the operator for approximately 82% of our Eagle Ford and 71% of our Haynesville acreage, including approximately 23% 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.

Our net proceeds from this offering, after discharging in full the $25.0 million term loan and repaying $10.0 million of the outstanding borrowings under our revolving Credit Agreement, when taken together with our cash flows and future potential borrowings under our Credit Agreement, will be used to fund the remainder of our 2011 and our entire 2012 exploration and development program and for potential acquisitions of interests and acreage. See “Use of Proceeds.”

 

 

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Index to Financial Statements

The following table presents our 2011 and 2012 anticipated capital expenditure budgets of approximately $148.9 million and $230.8 million, respectively. From January 1, 2011 through July 31, 2011, we spent approximately $84.2 million in capital expenditures (or 57% of our 2011 capital expenditures budget). Approximately 70% and 23% of these expenditures were spent in the development of our acreage in the Eagle Ford shale play and the core area of the Haynesville shale play, respectively. From August 1, 2011 through December 31, 2011, we anticipate that our capital expenditures will be approximately $64.7 million. While we have budgeted $148.9 million for 2011 and $230.8 million for 2012, the aggregate amount of capital we will expend may fluctuate materially based on market conditions and the outcome of our drilling results during the remainder of 2011 and in 2012. Since approximately 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 June 30, 2011, we have the financial flexibility to allocate our capital when we believe it is economical and justified.

 

    2011-2012 Anticipated Drilling      Anticipated Capital Expenditure Budgets  
    Gross  Wells(1)      Net Wells(1)      2011 (in  millions)(2)     2012 (in  millions)(2)  

South Texas:

         

Eagle Ford

    27.0         26.3       $ 58.2      $ 168.8   

Austin Chalk

    2.0         2.0                8.0   
 

 

 

    

 

 

    

 

 

   

 

 

 

Area Total

    29.0         28.3         58.2        176.8   
 

 

 

    

 

 

    

 

 

   

 

 

 

NW Louisiana/E Texas:

         

Haynesville

    70.0         7.4         42.5        27.5   

Cotton Valley

    1.0         1.0         5.1          
 

 

 

    

 

 

    

 

 

   

 

 

 

Area Total

    71.0         8.4         47.6        27.5   
 

 

 

    

 

 

    

 

 

   

 

 

 

SW Wyoming, NE Utah, SE Idaho

    2.0         0.8         1.5 (3)      1.5 (3) 

SE New Mexico, West Texas

                             

Other

    N/A         N/A         41.6 (4)      25.0 (5) 
 

 

 

    

 

 

    

 

 

   

 

 

 

Total

    102.0         37.5       $ 148.9      $ 230.8   
 

 

 

    

 

 

    

 

 

   

 

 

 

 

(1) Includes wells we currently expect to drill and complete as operator, plus those wells in which we currently plan to participate in the remainder of 2011 and in 2012. Also includes wells we have drilled to date in 2011.

 

(2) Our capital expenditure budgets are based on our net working interests in the properties. Also includes 2011 costs for wells drilled in 2010 and completed in early 2011 and costs for wells drilled to date in 2011.

 

(3) We have a carried interest for $4.2 million of the cost of drilling the initial test well on this prospect and a carried interest for $5.0 million if a second test well is drilled on this prospect. We began drilling the initial test well, the Crawford Federal #1, in Lincoln County, Wyoming in February 2011. 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 expect to resume operations on this initial test well in September 2011.

 

(4) Includes primarily leasehold costs, but also 2-D and 3-D seismic and other miscellaneous capital expenses such as recompletion expenses. A majority of these expenses are allocated to our acreage in the Eagle Ford and Haynesville shale plays. Also includes $32.6 million and $2.7 million incurred for leasehold acquisitions in the Eagle Ford and Haynesville shale plays, respectively, at July 31, 2011.

 

(5) Includes $20.0 million to acquire additional leasehold interests primarily prospective for oil and liquids production in southeast New Mexico and west Texas.

 

 

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Index to Financial Statements

Recent Developments

In August 2011, we completed our fourth operated Eagle Ford horizontal well, the Lewton #1H in DeWitt County, Texas. We are preparing to flow test this well following a 17-stage hydraulic fracture treatment. 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.

On May 19, 2011, the borrowing base under our credit agreement was increased to $80.0 million. On May 19, 2011, primarily to fund our acquisition of the new Eagle Ford acreage from Orca ICI Development, JV, we borrowed an additional $10.0 million under our credit agreement (bringing our total to $60.0 million) and borrowed an additional $25.0 million as a term loan. Out of the net proceeds we receive from this offering, we intend to repay the term loan in full and reduce borrowings under our credit agreement by approximately $10.0 million, leaving $50.0 million of long-term indebtedness outstanding after this offering.

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 well at a constrained rate of about 10.0 MMcf of natural gas per day that we believe optimizes overall well economics, even though we believe that this well was initially capable of delivering 20.0 to 25.0 MMcf of natural gas per day. During June 2011, this well produced at an average daily rate of 8.4 MMcf of natural gas per day and had produced approximately 0.9 Bcf of natural gas at June 30, 2011. 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. This well has been shut-in while we negotiate a pipeline right-of-way and prepare to lay a gas sales line to the well, which we anticipate will be completed in September 2011. 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 LaSalle County, Texas. First sales of oil and natural gas from this well began in late

 

 

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Index to Financial Statements

March at approximately 700 Bbls of oil and 350 Mcf of natural gas per day. At June 30, 2011, the well was producing approximately 500 Bbls of oil and 700 Mcf of natural gas per day, and through June 30, 2011, had produced a total of approximately 58,000 Bbls of oil and 50 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 LaSalle County, at approximately 3.4 MMcf of natural gas and 135 Bbls of condensate per day. At June 30, 2011, the well was producing approximately 1.0 MMcf of natural gas and 25 Bbls of condensate per day, and through June 30, 2011, had produced a total of approximately 300 MMcf of natural gas and 8,700 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. At June 30, 2011, the well was producing approximately 3.0 MMcf of natural gas per day and through June 30, 2011, had produced a total of approximately 600 MMcf of natural gas. We have been producing this well at a constrained natural gas rate. 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 that we believe optimizes overall well economics, even though we believe that this well was initially capable of delivering 20.0 to 25.0 MMcf of natural gas per day. At June 30, 2011, the well was producing approximately 10.6 MMcf of natural gas per day, and through June 30, 2011, had produced a total of approximately 1.7 Bcf of natural gas. We are the operator and have a 95% working interest in this well.

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. While we intend to allocate a portion of our 2011 and 2012 capital expenditure budgets to financing exploration, development and acquisition of additional interests in the Haynesville shale play, we currently intend to dedicate approximately 63% of our 2011 and approximately 74% of our 2012 capital expenditure budgets to the exploration, development and acquisition of additional interests in the Eagle Ford shale play. Since approximately 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 June 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.

 

 

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

Although most of our proved reserves are currently 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 development of locations that are prospective for oil and liquids. At July 31, 2011, we had spent approximately $58.9 million on oil and liquids exploration and acreage acquisition activities in 2011 and expect to spend approximately $35.4 million on oil and liquids exploration and acreage acquisition activities during the remainder of 2011. We believe oil and liquids opportunities represent a substantial portion of our anticipated 2011 and 2012 drilling capital expenditure budgets. 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 Low Cost Structure and Financial Discipline.

As an operator, we seek to manage aggressively our costs by leveraging advanced technologies and integrating the knowledge, judgment and experience of our management and technical teams. We believe our team demonstrates financial discipline that is reflected in the improvements it has achieved on reducing unit costs and is achieved by our approach to evaluating and analyzing prospects and prior drilling and completion results before allocating capital. When we are not the operator, we proactively engage with the operators in an effort to ensure similar financial discipline and cost-focused operations and results. 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 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.

 

 

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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 825 gross and 315 net drilling locations, including 192 gross and 157 net locations in the Eagle Ford shale play and 557 gross and 106 net locations in the Haynesville shale play. Approximately 15% of our Haynesville and 1% of our Eagle Ford gross locations have been included in our estimated proved reserves at March 31, 2011. We have identified 27 gross and 26 net locations in the Eagle Ford shale play and 70 gross and seven net locations in the Haynesville shale play that we expect to drill in 2011 and 2012, the completion of which would represent approximately 14% and 13% of our identified gross drilling locations in these two areas, 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.

 

   

Financial Flexibility to Fund Expansion.

Historically, we have maintained financial flexibility by obtaining capital through shareholder investments and our operational cash flows while maintaining low levels of indebtedness, which has allowed us to take advantage of acquisition opportunities as they arise. Upon the completion of this offering and the repayment of our $25.0 million term loan in full and $10.0 million of our outstanding borrowings under our revolving credit agreement, we expect to have at least $ million in cash, cash equivalents and certificates of deposit and at least $30.0 million available for borrowings under our credit agreement. Excluding any possible acquisitions, we expect to maintain our current financial flexibility by funding our remaining 2011 and entire 2012 capital expenditure budgets through the net proceeds from this offering, together with our operational cash flows and future potential borrowings under our credit agreement. 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 June 30, 2011, we have the financial flexibility to allocate our capital when we believe it is economical and justified.

 

 

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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 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-mortem” 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 development program or expand our positions in certain areas. Other times, this approach results in a decision to mitigate risk associated with our exploration and

 

 

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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.

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. The substantial volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations;

 

   

Low natural gas prices in the future could adversely impact us as our current production and reserves consist primarily of natural gas and many of our exploration prospects and development opportunities focus on natural gas;

 

   

Low oil prices in the future could adversely impact us as most of our near-term exploration opportunities in the Eagle Ford shale play focus on oil and liquids;

 

   

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 our actual reserves, 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, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth;

 

   

The mechanical risks of drilling and completion activities as well as 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, production problems and markets related 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 have limited control over activities on properties we do not operate;

 

   

Approximately 65% of our total proved reserves at March 31, 2011 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced;

 

 

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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 advisors could disrupt our business operations; and

 

   

If one or more material weaknesses persist or if we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

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 20 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 our reasonable judgment and reflects an approximation of 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 , 2011.

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

Common stock offered by us

   shares ( shares if the underwriters’ over-allotment is exercised in full)

Common stock outstanding after offering

  

shares ( shares if the underwriters’ over-allotment is exercised in full)

 

The number of shares to be outstanding after this offering is based on shares of our common stock outstanding at , 2011 and excludes additional shares that are authorized for future issuance under our equity incentive plans, of which shares may be issued pursuant to outstanding stock options.

Over-allotment option

   We have granted the underwriters a 30-day option to purchase up to an aggregate of additional shares of our common stock to cover any over-allotments.

Use of proceeds

  

We estimate that our net proceeds from this offering will be approximately $ million after deducting the underwriting discounts and commissions and estimated offering expenses.

 

We intend to use approximately $25.0 million of the net proceeds from this offering to repay in full our outstanding term loan. In addition, we intend to use approximately $10.0 million from this offering to repay a portion of the outstanding indebtedness under our revolving credit agreement, approximately $60.0 million of which was outstanding on June 30, 2011. The remaining net proceeds will be used to fund a portion of our 2011 and a portion of our anticipated 2012 capital expenditure budgets and for other general corporate purposes. See “Use of Proceeds.”

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 20 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 three months ended March 31, 2011 and 2010. The balance sheet data has also been adjusted to reflect (i) the $20.0 million of additional borrowings under our revolving credit agreement and our borrowings of $25.0 million under the term loan which occurred during the second quarter of 2011, (ii) the $30.5 million spent since March 31, 2011 to acquire leasehold interests in the Eagle Ford shale play from Orca ICI Development, JV ($1.0 million of the total cost of this acquisition was paid in March 2011) and (iii) the estimated net proceeds 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 three months ended March 31, 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,     Three Months Ended
March 31,
 
     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      $ 13,699      $ 9,190   

Realized gain (loss) on derivatives

     5,299        7,625        (1,326     1,850        302   

Unrealized gain (loss) on derivatives

     3,139        (2,375     3,592        (1,668     6,093   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     42,480        24,289        32,911        13,880        15,585   

Expenses:

          

Production taxes and marketing

     1,982        1,077        1,639        1,300        267   

Lease operating

     5,284        4,725        4,667        1,605        1,332   

Depletion, depreciation and amortization

     15,596        10,743        12,127        7,111        3,362   

Accretion of asset retirement obligations

     155        137        92        39        38   

Full-cost ceiling impairment

            25,244        22,195        35,673          

General and administrative

     9,702        7,115        8,252        2,619        2,032   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

     32,719        49,041        48,972        48,347        7,031   

Operating income (loss)

     9,761        (24,752     (16,061     (34,467     8,554   

Other:

          

Other (expense) income

     137        402        139,962 (1)      (35     96   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

     9,898        (24,350     123,901        (34,502     8,650   

Net income (loss)

   $ 6,377      $ (14,425   $ 103,878      $ (27,596   $ 5,676   

 

 

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     Year Ended December 31,      Three Months Ended
March 31,
 
     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       $ (0.65   $ 0.14   

Class B(2)

   $ 0.42       $ (0.10   $ 2.77       $ (0.58   $ 0.21   

Weighted average common shares outstanding (basic)

     41,037         40,123        41,385         42,655        41,414   

Class A

     40,007         39,093        40,355         41,625        40,384   

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 July 31, 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 March 31,  
    2010     2009     2008     2011     2010  
                      Actual     As
Adjusted(1)
    As Further
Adjusted(2)
       
(In thousands)                     (Unaudited)     (Unaudited)     (Unaudited)     (Unaudited)  

Balance sheet data:

             

Cash and cash equivalents

  $ 21,060      $ 104,230      $ 150,768      $ 14,461      $ 28,961      $ 130,961      $ 91,619   

Certificates of deposit

    2,349        15,675        20,782        2,079        2,079        2,079        14,674   

Net property and equipment

    303,880        142,078        125,261        301,098        331,598        331,598        160,057   

Total assets

    346,382        277,400        314,539        336,197        381,197        483,197        285,788   

Current liabilities

    30,097        8,868        35,475        37,444        62,444        37,444        9,964   

Long term liabilities

    34,408        4,210        2,059        43,943        63,943        53,943        5,610   

Total shareholders’ equity

  $ 281,877      $ 264,321      $ 277,005      $ 254,809      $ 254,809      $ 391,809      $ 270,214   

 

(1) As adjusted for (i) the $20.0 million of additional borrowings under our revolving credit agreement and our borrowings of $25.0 million under the term loan which occurred during the second quarter of 2011, and (ii) the $30.5 million spent since March 31, 2011 to acquire leasehold interests in the Eagle Ford shale play from Orca ICI Development, JV. $1.0 million of the total cost of this acquisition was paid in March 2011.

 

(2) As further adjusted to give effect to this offering (assuming aggregate gross proceeds of $150.0 million) and the application of the estimated net proceeds to repay our $25.0 million term loan in full and repay approximately $10.0 million under our revolving credit agreement, with the balance being added to cash and cash equivalents to fund a portion of our 2011 and a portion of our anticipated 2012 capital expenditure budgets and for other general corporate purposes.

 

     Year Ended December 31,     Three Months Ended
March 31,
 
     2010     2009     2008     2011     2010  
(In thousands)                      (Unaudited)     (Unaudited)  

Other financial data:

          

Net cash provided by operating activities

   $ 27,273      $ 1,791      $ 25,851      $ 12,732      $ 9,101   

Net cash (used in) provided by investing activities

     (147,334     (49,415     115,481        (35,024     (21,743

Oil and natural gas properties capital expenditures

     (159,050     (54,244     (104,119     (34,114     (22,208

Expenditures for other property and equipment

     (1,610     (307     (3,012     (1,180     (536

Net cash provided by financing activities

     36,891        1,086        419        15,693        31   

Adjusted EBITDA(1)

   $ 23,635      $ 15,184      $ 18,411      $ 10,148      $ 6,142   

 

(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.

 

 

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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 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.

 

 

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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,     Three Months
Ended

March 31,
 
     2010     2009     2008     2011     2010  
(In thousands)       

Unaudited Adjusted EBITDA reconciliation to Net Income (Loss):

          

Net income (loss)

   $ 6,377      $ (14,425   $ 103,878      $ (27,596   $ 5,676   

Interest expense

     3                      106          

Total income tax provision (benefit)

     3,521        (9,925     20,023        (6,906     2,975   

Depletion, depreciation and amortization

     15,596        10,743        12,127        7,111        3,362   

Accretion of asset retirement obligations

     155        137        92        39        38   

Full-cost ceiling impairment

            25,244        22,195        35,673          

Unrealized (gain) loss on derivatives

     (3,139     2,375        (3,592     1,668        (6,093

Stock option and grant expense

     824        622        605        42        180   

Restricted stock grants

     74        34        60        11        6   

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

     224        379        (136,977              
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 23,635      $ 15,184      $ 18,411      $ 10,148      $ 6,142   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
     Year Ended December 31,     Three Months
Ended

March 31,
 
     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      $ 12,732      $ 9,101   

Net change in operating assets and liabilities

     (2,230     15,717        (17,888     (2,690     (2,959

Interest expense

     3                      106          

Current income tax (benefit) provision

     (1,411     (2,324     10,448                 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 23,635      $ 15,184      $ 18,411      $ 10,148      $ 6,142   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

 

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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 March 31, 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 March 31,  
     2010     2009     2008     2011  

Estimated proved reserves:(1) (2)

        

Natural gas (Bcf)

     127.4        63.9        19.2        150.1   

Oil (MBbls)

     152        103        131        780   

Total (Bcfe)

     128.3        64.5        20.0        154.8   

Developed proved reserves (Bcfe)

     44.1        26.0        20.0        56.1   

Percent developed

     34.3     40.3     100.0     36.2

Undeveloped proved reserves (Bcfe)

     84.3        38.6               98.7   

PV-10 (in thousands)(3)

   $ 119,869      $ 70,359      $ 44,069      $ 140,639   

Standardized Measure (in thousands)(4)

   $ 111,077      $ 65,061      $ 43,254      $ 131,521   

 

(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 April 2010 to March 2011 were $80.04 per Bbl for oil and $4.102 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 March 31, 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, in thousands, at December 31, 2008, 2009 and 2010 and at March 31, 2011 were $815, $5,298, $8,792 and $9,118, 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 three month periods ended  March 31, 2011 and 2010.

 

     Year Ended December 31,      Three Months Ended
March  31,
 
       2010          2009          2008          2011          2010    

Production:

              

Natural gas (Bcf)

     8.4         4.8         3.1         3.3         1.8   

Oil (MBbls)

     33         30         37         19         8   

Total natural gas equivalents (Bcfe)(1)

     8.6         5.0         3.3         3.4         1.8   

Average net daily production (MMcfe)

     23.6         13.7         9.0         37.8         20.5   

Average sales price (per Mcfe):

              

Average sales price (including effects of hedging)

   $ 4.58       $ 5.33       $ 8.86       $ 4.57       $ 5.14   

Average sales price (before effects of hedging)

   $ 3.96       $ 3.81       $ 9.27       $ 4.03       $ 4.98   

Operating expenses (per Mcfe):

              

Production taxes and marketing

   $ 0.23       $ 0.22       $ 0.50       $ 0.38       $ 0.14   

Lease operating

   $ 0.61       $ 0.94       $ 1.41       $ 0.47       $ 0.72   

Depletion, depreciation and amortization

   $ 1.81       $ 2.15       $ 3.67       $ 2.09       $ 1.82   

General and administrative

   $ 1.13       $ 1.42       $ 2.50       $ 0.77       $ 1.10   

 

  (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. 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 influences our revenue, profitability, 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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Prices for oil and natural gas will affect the amount of cash flow available to us for capital expenditures and our ability to borrow and raise additional capital. Our ability to initiate, maintain or increase our borrowing capacity and to obtain additional capital on attractive terms is also substantially dependent upon oil and natural gas prices. Declines in oil and natural gas prices would not only reduce our revenue, but could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. In addition, 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. 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.

Low Natural Gas Prices in the Future Could Adversely Impact Us as Our Current Production and Reserves Consist Primarily of Natural Gas and Many of Our Exploration Prospects and Development Opportunities Focus on Natural Gas.

Approximately 98% of our production during the year ended December 31, 2010, 95% of our production during the five month period ended May 31, 2011 and 97% of our proved reserves at March 31, 2011 are attributable to natural gas. In addition, three of our largest prospects, our Haynesville shale and 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. Natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical conditions. Should natural gas prices remain at current levels for an extended period of time, our future natural gas revenues, as well as the economic viability of our natural gas prospect inventory, will be adversely impacted. We may also elect to delay some of our exploration and development plans for these prospects until natural gas prices improve. If there are further declines in natural gas prices, we may be unable to develop these properties further or to conduct exploration activities on these prospects at all.

Low Oil Prices in the Future Could Adversely Impact Us as Most of Our Near-term Exploration Opportunities in the Eagle Ford Shale Play Focus on Oil and Liquids.

We currently intend to dedicate 63% of our 2011 and 74% of our 2012 capital expenditure budgets 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 192 gross locations for potential future drilling in our Eagle Ford acreage. Since a significant portion of our near-term exploration strategy focuses on oil and liquids in the Eagle Ford shale play, low oil prices in the future would adversely impact our results of operations, financial condition and cash flows. Oil prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical conditions. Should oil prices decrease from current levels and remain there for an extended period of time, our future oil revenues, as well as the economic viability of our oil prospect inventory, would be adversely impacted. In that case we might also elect to delay some of our exploration and development plans for these prospects until oil prices improve. If there were further declines in oil prices, we might be unable to develop these properties further or to conduct exploration activities on these prospects at all.

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.

Drilling activities involve the 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

 

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are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Whether a well is productive and profitable depends on a number of 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;

 

   

mechanical problems encountered in drilling wells or in production activities;

 

   

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;

 

   

localized supply and demand fundamentals;

 

   

proximity to and capacity of transportation facilities;

 

   

price and availability of competitors’ supplies of oil and natural gas;

 

   

technological advances affecting energy consumption; and

 

   

the price and availability of alternative fuels.

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

In addition to the substantial risk that we may not drill productive and profitable wells, numerous hazards are inherent in oil and natural gas exploration, development, production and gathering, including:

 

   

unusual or unexpected geologic formations;

 

   

natural disasters;

 

   

unanticipated pressures;

 

   

mechanical failures;

 

   

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 failures or casing collapses;

 

   

fires or explosions;

 

   

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

 

   

environmental accidents such as uncontrollable flows of oil, natural gas or well fluids into the environment, including groundwater contamination.

 

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We could suffer substantial losses from these hazards due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. We do not fully insure against all risks associated with our business, either because this insurance is not available or because we believe the cost is prohibitive. The occurrence of an event that is not covered, or not fully covered, by insurance could decrease cash flow and net revenues and negatively affect our financial condition if we incur cleanup costs or must settle claims related to these hazards.

Because Our Reserves and Production Are Concentrated in a Small Number of Properties, Production Problems and Markets Related 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 producing 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, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in these areas. 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. If future production declines in wells in these areas are greater than we have estimated, the results of our operations and financial condition will be adversely affected. If the actual reserves associated with our fields are less than our estimated reserves, our results of operations and financial condition will be adversely affected.

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 oil and natural gas properties declines as reserves are depleted. We must continue to grow our reserves and cash flow by successfully drilling for oil and natural gas production on properties owned by us or by other persons or entities and/or by the acquisition of producing properties. We may have to drill even during periods of low oil and natural gas prices when it is difficult to raise the capital necessary to finance activities. Our future oil and natural gas reserves and production and, therefore, our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional reserves. We may not be successful in drilling for oil and natural gas production. In the future, we may have difficulty expanding our current production through acquisitions and/or by additional drilling for oil and natural gas production. 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 Our Actual Reserves, 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

 

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process also requires certain economic assumptions, such as 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 based on that data.

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. Any significant variance could materially affect the quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors. Our reserves may also be susceptible to drainage by operators on adjacent properties.

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 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.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value.

 

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Approximately 65% of Our Total Proved Reserves at March 31, 2011 Consisted of Undeveloped and Developed Non-Producing Reserves, and Those Reserves May Not Ultimately Be Developed or Produced.

At March 31, 2011, approximately 64% of our total proved reserves were undeveloped and approximately 1% were developed non-producing. While we plan to develop and produce all of our proved reserves, these reserves may not ultimately be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced at the time periods we have projected, at the costs we have budgeted or at all. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. 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.

Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures, 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. Future events, such as terrorist attacks, a war or combat peace-keeping mission, a financial market disruption, a general economic recession, an oil and natural gas industry recession or large company bankruptcies, could adversely affect the availability and cost of capital for our business. Accounting scandals, public company bankruptcies, 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. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be attractive. If our ability to access capital on attractive terms becomes significantly constrained, our financial condition and future results of operations could be adversely affected.

If our revenues decrease as a result of lower product 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 or to further develop and exploit our current properties, or for exploration activities. In order to fund our capital expenditures, we may need to seek additional financing. Our current revolving credit agreement contains covenants restricting our ability to incur additional indebtedness. In addition, if our borrowing base is redetermined resulting in a lower borrowing base under our revolving credit agreement, we may be unable to obtain financing that is currently available under our revolving credit agreement.

A significant improvement in product prices could result in an increase in our capital expenditures. While we believe the net proceeds from this offering, together with our cash flows and future potential borrowings under our revolving credit agreement, will be adequate to fund our anticipated capital expenditures and any acquisitions for the remainder of 2011 and all of 2012, funding for future acquisitions or our future capital expenditure requirements may require us to alter or increase our capitalization substantially through the issuance of debt or additional equity securities, the sale of production payments or the sale of non-strategic assets. The issuance or incurrence of debt may require that a portion of our cash

 

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flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.

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 production;

 

   

our ability to acquire, locate and produce new reserves;

 

   

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

 

   

our ability to access the equity and debt capital markets.

Drilling Wells Is Speculative, Often Involving Significant Costs that May Be More than Our Estimates, and May Not Result in any Discoveries or Additions to Our Future Production or Reserves. Any Material Inaccuracies in Drilling Costs, Estimates or Underlying Assumptions Will Materially Affect Our Business.

Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services or unanticipated geologic conditions. 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. Exploratory wells bear a much greater risk of loss than development wells. Furthermore, 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.

Exploration Is a High-Risk Activity, and 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.

Our future success will depend in large part on the success of our exploratory drilling program. Exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. In addition, we often are uncertain as to the future costs or timing of drilling, completing and producing wells. Furthermore, our drilling operations may be curtailed, delayed or canceled as a result of the additional exploration time and expense associated with a variety of factors, including:

 

   

unexpected adverse drilling conditions;

 

   

pressures or irregularities in formations;

 

   

equipment failures or accidents;

 

   

mechanical difficulties;

 

   

adverse weather conditions;

 

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limitations in the market for oil and natural gas;

 

   

title problems;

 

   

compliance with governmental requirements; and

 

   

shortages or delays in the availability of drilling rigs and other oilfield services and equipment, including hydraulic fracturing equipment, as well as shortages of qualified personnel to provide these services.

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 activities. 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 Mechanical Risks of Drilling and Completion Activities as well as 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.

The mechanical risks of drilling and completion activities could adversely affect our ability to execute exploration and development plans within budget and on a timely basis. 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 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.

 

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Drilling Locations That We Decide to Drill May Not Yield Oil or Natural Gas in Commercially Viable Quantities.

We describe some of our drilling locations and our plans to explore those drilling locations in this prospectus. Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation before it can be drilled. 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 drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities 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 while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. 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. The cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

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 many of our properties. As a result, 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, reflecting 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 current revolving credit agreement includes covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions with stock, our shareholders would suffer dilution of their interests. While we intend to concentrate on acquiring producing properties with exploration and development potential located in areas of operation with which our staff is familiar, we may decide to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar, which may impact our productivity in such areas.

We May Purchase Oil and Natural Gas Properties with Liabilities or Risks 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.

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

There are a variety of operating risks inherent in our wells, gathering systems, pipelines and other facilities, such as leaks, explosions, mechanical problems and natural disasters, all of which could cause substantial financial losses. 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. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations 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 costs and 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. Additionally, we anticipate further tightening of the insurance markets in the aftermath of the Macondo well incident in the Gulf of Mexico in April 2010. 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 we cannot be sure the insurance coverage we do obtain will cover certain hazards or all potential losses, and will not contain 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.

 

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Weather Conditions Could Materially Impair Our Business.

Our operations in south Texas may be adversely affected by hurricanes and tropical storms, resulting in delays in exploration and drilling. Adverse weather can also directly impede our operations. Repercussions of severe weather conditions may include:

 

   

curtailment of operations;

 

   

weather-related damage to facilities and equipment, resulting in suspension of operations;

 

   

inability to receive equipment, personnel and products to job sites in a timely manner;

 

   

increase in the price of insurance; and

 

   

loss of productivity.

These constraints could also delay our operations, reduce our revenues and materially increase our operating and capital costs.

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 natural gas 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 put and call options in the form of costless collars with respect to a portion of our future production. The goal of these 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 and natural gas prices rise above the maximum price established by the options and may offer protection if prices fall below the minimum price established by the options only to the extent of the volumes then hedged.

 

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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 product 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 natural gas hedges will expire at various times during 2011, 2012 and 2013. We currently have no hedging agreements in place for any of our oil and liquids production.

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, New Taxes and Changes to Tax Laws, All of 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;

 

   

containment and clean up of oil and other spills;

 

   

the management and disposal of hazardous materials;

 

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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 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.

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.

Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities May Be Eliminated as a Result of Future Legislation.

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 United States production activities and (iv) the increase in the amortization period for 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. In 2009 and 2010, legislation which would have implemented the proposed changes was introduced but not enacted. 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.

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 and natural gas prices are low. In addition, non-cash write-downs may occur if we have:

 

   

downward adjustments to our estimated proved reserves;

 

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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 ceiling limit 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 ceiling limit, 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. There is no assurance that we will not 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.

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

We regularly enter into commodity hedges which would compensate us in the event that commodity prices decrease. Those hedges are intended to partially offset a decrease in revenue from a drop in commodity prices and decrease our exposure generally to commodity price volatility. 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

 

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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.

The imposition of these types of requirements or limitations could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity. If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues from sales of commodities and may decrease the amount of credit that lenders are willing to extend to us. It should be further noted that the use of derivative arrangements can play an important role in our acquisition strategies; therefore, any limitations or changes in our use of derivative arrangements could also 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 is currently considering 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, including, for example, the Fracturing Responsibility and Awareness of Chemicals Act. 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, where we focus our operations. Sponsors of bills pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. These bills, 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, announced on March 18, 2010 that it allocated $1.9 million in 2010 and has requested funding in fiscal year 2011 for conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on human health and the environment. Consequently, even if these bills are 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. 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.

 

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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 could trigger permit review for 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. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations and cause us to incur significant costs in preparing for or responding to those effects.

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. While our systems have not 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.

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 June 30, 2011, we had leasehold interests in approximately 137,000 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 over the next several years. 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 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

 

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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 the co-owners of our non-operated properties 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 the 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, we expect to have approximately $50.0 million of long-term debt outstanding and available borrowings of approximately $30.0 million. Our current maximum borrowing capacity is the borrowing base, which at June 30, 2011 was $80.0 million, under our revolving credit agreement. Our borrowing base is determined semi-annually by our lenders based primarily on estimates of our proved oil and natural gas reserves. In addition to our revolving credit agreement, in May 2011, we borrowed $25.0 million in a term loan pursuant to the credit agreement. The term loan is due and payable on December 31, 2011, and there is no penalty for prepayment. At June 30, 2011, the term loan and the revolving loan bore interest at approximate annual rates of 5.3% and 2.1%, respectively. Once we discharge the term loan in full with a portion of the net proceeds from this offering, we will not be able to borrow any further amounts under the term loan. In the future, we may incur additional indebtedness, which may be significant, 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;

 

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the covenants contained in the agreements governing our outstanding indebtedness will 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 would 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.

In addition, the borrowing base under our revolving credit agreement is subject to periodic redeterminations. We could be forced to repay a portion of our bank 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. 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 Advisors 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 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. While we have entered into employment agreements with Mr. Foran and other key personnel, such 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 through 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

 

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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 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.

Our Management Team Will Own Approximately % 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 % of our outstanding shares of common stock following this offering based on  shares of common stock to be sold in 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 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. We intend to file a listing application with the New York Stock Exchange, or NYSE, for our common stock in connection with this offering, which is subject to official notice of issuance. 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 will be 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 $ Per Share.

Based on an assumed initial public offering price of $ per share, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $ 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 December 31, 2010 after giving effect to this offering would be $ per share. See “Dilution” for a complete description of the calculation of net tangible book value.

While We Currently Intend to Use the Net Proceeds from this Offering as Set Forth Under “Use of Proceeds” in this Prospectus, Our Budgets May Change Throughout 2011 and 2012 Depending on Oil and Natural Gas Prices, the Outcome of Our Drilling and Exploration Programs and Proposed Acquisitions.

While we intend to use the net proceeds from this offering and from any exercise of the underwriters’ over-allotment option to discharge our $25.0 million term loan in full, repay $10.0 million of our outstanding borrowings under our revolving credit agreement, fund the remaining portion of our 2011 and a portion of our anticipated 2012 capital expenditure budgets and for other general corporate purposes, following this offering, we may determine to revise the remainder of our 2011 and 2012 capital expenditure budgets based on the then current oil and natural gas prices and the outcome of our drilling and exploration programs. In addition, we may spend some or all of the net proceeds from this offering to consummate acquisitions of interests and acreage if we are presented with attractive acquisition opportunities. Management has broad discretion in applying the net proceeds of this offering. Our shareholders may not agree with the manner in which our management chooses to allocate and spend the net proceeds of 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 One or More Material Weaknesses Persist or if We Fail to Establish and Maintain Effective Internal Control over Financial Reporting, 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 annual report is required to be filed with the SEC. Once they are required to do so, our independent

 

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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, prohibition on the payment of dividends and the repurchase of shares of our common stock are imposed under our revolving credit agreement. 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 will ever exceed the price that you pay.

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 shares outstanding at , 2011, upon completion of this offering, we will have outstanding approximately shares of common stock, and in addition to the shares sold in this offering, shares of common stock will be immediately freely tradable, without restriction, in the public market. The underwriters expect that of our shares, including all shares held by our officers and directors, will be 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. We expect to contact our shareholders to discuss and obtain these agreements following the initial filing of this prospectus. 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 this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of shares of our common stock issuable or reserved for issuance under our 2003 Stock and Incentive Plan and our 2011 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. Sales of substantial amounts of our common stock or convertible securities (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices 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.

Provisions of our certificate of formation and bylaws 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 10% 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,” “will,” “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.

 

 

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USE OF PROCEEDS

We will receive net proceeds of approximately $  million from the sale of the common stock offered by us, assuming an initial public offering price of $  per share (the midpoint of the price range set forth on the cover page of this prospectus) and after deducting estimated expenses of approximately $  million and estimated underwriting discounts and commissions of approximately $ million. If the underwriters’ over-allotment option is exercised in full, we estimate that our net proceeds will be approximately $ million.

Initially, we intend to use the net proceeds from this offering to repay in full the $25.0 million term loan that is due and payable on December 31, 2011 and to repay approximately $10.0 million of the outstanding indebtedness under our revolving credit agreement, approximately $60.0 million of which was outstanding on June 30, 2011. Following the application of the net proceeds of this offering, we will have approximately $50.0 million of long-term indebtedness outstanding and $30.0 million available for potential future borrowings.

We intend to use the remaining proceeds from this offering, together with our cash flows and future potential borrowings under our revolving credit agreement, to fund the remainder of our anticipated 2011 and our entire 2012 capital expenditure requirements and for other general corporate purposes, which may include additional drilling and development expenditures or acquisitions of interests and acreage. From January 1, 2011 through July 31, 2011, we spent approximately $84.2 million in capital expenditures (or 57% of our 2011 capital expenditures budget). From August 1, 2011 through December 31, 2011, we anticipate that our capital expenditures will be approximately $64.7 million.

The $25.0 million term loan matures on December 31, 2011 and bears interest at a rate of 5% plus a Eurodollar-based rate per annum, which equated to approximately 5.3% at June 30, 2011. For more information regarding our term loan, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Credit Agreement.”

Our revolving credit agreement matures in March 2013 and our borrowings bear interest at a variable rate of 1.875% plus a Eurodollar-based rate per annum, which equated to approximately 2.1% at June 30, 2011. Our outstanding borrowings under our revolving credit agreement were incurred from December 2010 through May 2011 to finance acquisitions of acreage and ongoing drilling and completion operations. For more information regarding our revolving credit agreement, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Credit Agreement.”

If the underwriters’ over-allotment option is exercised in full, any additional net proceeds will be added to our working capital and used for general corporate purposes.

An increase or decrease in the initial public offering price of $1.00 per share of common stock would cause the net proceeds that we will receive from this offering, after deducting estimated expenses and underwriting discounts and commissions, to increase or decrease by approximately $ million.

While we expect to use the proceeds from this offering in the manner set forth above, the ultimate uses of our capital may differ depending on market conditions and the outcome of our drilling results. Until the actual use of our net proceeds from this offering as described above, we intend to invest such net proceeds in U.S. treasury bonds or investment grade instruments.

 

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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, a prohibition on the payment of dividends on our common stock is imposed under our revolving credit agreement.

 

 

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CAPITALIZATION

The following table sets forth our capitalization at March 31, 2011. Our capitalization is presented:

 

   

on an actual basis;

 

   

on an as adjusted basis to give effect to $20.0 million of additional borrowings under our revolving credit agreement, our new $25.0 million term loan due on December 31, 2011 and our May 2011 acquisition of acreage in the Eagle Ford shale play for $30.5 million ($1.0 million of the total cost of this acquisition was paid in March 2011); and

 

   

on an as further adjusted basis to give effect to this offering (assuming aggregate gross proceeds of $150.0 million), the application of the estimated net proceeds to repay our $25.0 million term loan in full and repay approximately $10.0 million under our revolving credit agreement, with the balance being added to cash and cash equivalents, and the conversion of our Class B common stock.

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 March 31, 2011  
     Actual     As Adjusted     As Further
Adjusted
 
(In thousands except for shares)       

Cash and cash equivalents

   $  14,461      $ 28,961      $ 130,961   

Certificates of deposit

     2,079        2,079        2,079   

Debt:

      

Short-term debt(1)

            25,000          

Long-term debt(2)

     40,000        60,000        50,000   

Shareholders’ equity:

      

Class A common stock, $0.01 par value, 80,000,000 shares authorized; 42,826,842 shares issued and 41,647,667 shares outstanding, actual; 42,826,842 shares issued and 41,647,667 shares outstanding, as adjusted; • shares issued and • shares outstanding, as further adjusted

     428        428          

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

     10        10          

Additional paid-in capital

     263,937        263,937          

Retained earnings

     1,198        1,198        1,198   

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

     (10,765     (10,765       
  

 

 

   

 

 

   

 

 

 

Total shareholders’ equity

   $ 254,809      $ 254,809      $   
  

 

 

   

 

 

   

 

 

 

Total capitalization

   $ 294,809      $ 339,809      $   
  

 

 

   

 

 

   

 

 

 

 

(1) In May 2011, we borrowed $25.0 million in a term loan pursuant to the credit agreement. The term loan is due and payable on December 31, 2011 and there is no penalty for prepayment. For more information regarding our term loan, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Credit Agreement.”

 

(2) In March 2008, we entered into a credit agreement to establish a secured revolving line of credit for a term of five years, which we amended and restated in May 2011. At June 30, 2011, the borrowing base was $80.0 million, and we had $60.0 million in borrowings outstanding under the agreement and $375,000 in outstanding letters of credit issued pursuant to the credit agreement. Approximately $19.6 million remained available for additional borrowings. For more information regarding our revolving credit agreement, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — 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 March 31, 2011 was approximately $255 million, or $5.97 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 (after deducting estimated discounts and expenses of this offering), our adjusted pro forma net tangible book value at March 31, 2011 would have been approximately $ million, or $ per share. This represents an immediate increase in the net tangible book value of $ per share to our existing shareholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $ 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

        $   

Pro forma net tangible book value per share at March 31, 2011

       

  

Increase per share attributable to new investors in this offering

          

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

          

Dilution in pro forma net tangible book value per share to new investors in this offering

        $   

The following table summarizes, on an as adjusted basis at March 31, 2011, the total number of shares of common stock owned by existing shareholders (assuming 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 $, the midpoint of the range of the initial public offering prices set forth on the cover page of this prospectus, calculated before deduction of estimated underwriting discounts and commissions:

 

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

Existing shareholders

     42,678,367                            

New investors

                                
  

 

 

    

 

 

   

 

 

    

 

 

   

Total

             100             100  
  

 

 

    

 

 

   

 

 

    

 

 

   

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 to % and will increase the number of shares held by new investors to , or % on an as adjusted pro forma basis at March 31, 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 three months ended March 31, 2011 and 2010 and the consolidated balance sheet data at March 31, 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 three month periods ended March 31, 2011 and 2010, and the notes thereto included herewith.

 

    Year Ended December 31,     Three Months Ended
March 31,
 
    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      $ 13,699      $ 9,190   

Realized gain (loss) on derivatives

    5,299        7,625        (1,326     213               1,850        302   

Unrealized gain (loss) on derivatives

    3,139        (2,375     3,592        (211            (1,668     6,093   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

    42,480        24,289        32,911        13,990        14,678        13,880        15,585   

Expenses:

             

Production taxes and marketing

    1,982        1,077        1,639        779        896        1,300        267   

Lease operating

    5,284        4,725        4,667        3,099        3,075        1,605        1,332   

Depletion, depreciation and amortization

    15,596        10,743        12,127        7,889        10,950        7,111        3,362   

Accretion of asset retirement obligations

    155        137        92        70        55        39        38   

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        2,619        2,032   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

    32,719        49,041        48,972        17,026        76,887        48,347        7,031   

Operating income (loss)

    9,761        (24,752     (16,061     (3,036     (62,209     (34,467     8,554   

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        71        96   

Interest expense

    (3                                 (106       
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

    137        402        139,962        2,736        2,063        (35     96   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

  $ 6,377      $ (14,425   $ 103,878      $ (300   $ (60,146   $ (27,596   $ 5,676   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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    At December 31,     At March 31,  
    2010     2009     2008     2007     2006     2011     2010  
                                  Actual     As
Adjusted(1)
    As Further
Adjusted(2)
       
                                  (Unaudited)     (Unaudited)     (Unaudited)     (Unaudited)  
(In thousands)      

Balance sheet data:

                 

Cash and cash equivalents

  $ 21,060      $ 104,230      $ 150,768      $ 9,017      $ 43,183      $ 14,461      $ 28,961      $ 130,961      $ 91,619   

Certificates of deposit

    2,349        15,675        20,782                      2,079        2,079        2,079        14,674   

Short-term investments

                         57,925                                      

Net property and equipment

    303,880        142,078        125,261        105,814        63,062        301,098        331,598        331,598        160,057   

Total assets

    346,382        277,400        314,539        179,152        112,628        336,197        381,197        483,197        285,788   

Current liabilities

    30,097        8,868        35,475        5,541        5,878        37,444        62,444        37,444        9,964   

Long term liabilities

    34,408        4,210        2,059        1,568        878        43,943        63,943        53,943        5,610   

Total shareholders’ equity

  $ 281,877      $ 264,321      $ 277,005      $ 172,043      $ 105,872      $ 254,809      $ 254,809      $ 391,809      $ 270,214   

 

     Year Ended December 31,     Three Months Ended
March 31,
 
     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      $ 12,732      $ 9,101   

Net cash (used in) provided by investing activities

     (147,334     (49,415     115,481        (108,296     (49,501     (35,024     (21,743

Oil and natural gas properties capital expenditures

     (159,050     (54,244     (104,119     (50,310     (51,932     (34,114     (22,208

Expenditures for other property and equipment

     (1,610     (307     (3,012     (1,300     (3,127     (1,180     (536

Net cash provided by financing activities

     36,891        1,086        419        66,250        73,876        15,693        31   

Adjusted EBITDA(3)

   $ 23,635      $ 15,184      $ 18,411      $ 8,091      $ 7,582      $ 10,148      $ 6,142   

 

(1) As adjusted for (i) the $20.0 million of additional borrowings under our revolving credit agreement and our borrowings of $25.0 million under the term loan which occurred during the second quarter of 2011, and (ii) the $30.5 million spent since March 31, 2011 to acquire leasehold interests in the Eagle Ford shale play from Orca ICI Development, JV. $1.0 million of the total cost of this acquisition was paid in March 2011.

 

(2) As further adjusted to give effect to this offering (assuming aggregate gross proceeds of $150.0 million) and the application of the estimated net proceeds to repay our $25.0 million term loan in full and repay approximately $10.0 million under our revolving credit agreement, with the balance being added to cash and cash equivalents to fund a portion of our 2011 and a portion of our anticipated 2012 capital expenditure budgets and for other general corporate purposes.

 

(3) 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 and 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 these plays 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 these 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 198 wells through June 30, 2011, including 65 Haynesville and six Eagle Ford wells. At March 31, 2011, based on the reserves report audit by our independent reservoir engineers, we had 154.8 Bcfe of estimated proved reserves with a PV-10 of $140.6 million and a Standardized Measure of $131.5 million. At March 31, 2011, 36% of our estimated proved reserves were proved developed reserves and 97% 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 recently completed and turned to sales, our daily production for the month ended May 31, 2011 was approximately 49.1 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 and natural gas prices would not only reduce our revenues, but could also reduce the amount of oil and 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 mechanical risks of drilling and completion activities as well as 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 and 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,     Three Months Ended
March 31,
 
     2010      2009     2008     2011     2010  
                        (Unaudited)     (Unaudited)  

Operating Results:

           

Revenues (in thousands):

           

Oil

   $ 2,506       $ 1,719      $ 3,653      $ 1,680      $ 633   

Natural gas

     31,535         17,320        26,992        12,019        8,557   
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Total oil and natural gas revenues

     34,042         19,039        30,645        13,698        9,190   

Realized gain (loss) on derivatives

     5,299         7,625        (1,326     1,849        302   

Unrealized gain (loss) on derivatives

     3,139         (2,375     3,592        (1,668     6,093   
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

   $ 42,480       $ 24,289      $ 32,911      $ 13,880      $ 15,585   

Net Production Volumes:

           

Oil (MBbls)

     33         30        37        19        8   

Natural gas (Bcf)

     8.4         4.8        3.1        3.3        1.8   

Total natural gas equivalents (Bcfe)

     8.6         5.0        3.3        3.4        1.8   

Average net daily production (MMcfe/d)

     23.6         13.7        9.0        37.8        20.5   

Average Sales Prices:

           

Oil (per Bbl)

   $ 76.39       $ 57.72      $ 98.59      $ 89.11      $ 75.29   

Natural gas, with realized derivatives (per Mcf)

   $ 4.38       $ 5.17      $ 8.32      $ 4.22      $ 4.93   

Natural gas, without realized derivatives (per Mcf)

   $ 3.75       $ 3.59      $ 8.75      $ 3.65      $ 4.76   

Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2010

Oil and natural gas revenues. Our oil and natural gas revenues increased by $4.5 million to $13.7 million, or an increase of about 49%, for the three months ended March 31, 2011, as compared to the three months ended March 31, 2010. We increased our production by 84% to 3.4 Bcfe for the three months ended March 31, 2011 from 1.8 Bcfe for the three months ended March 31, 2010 primarily due to drilling operations in the Haynesville shale, but also reflects production from our first operated well in the Eagle Ford shale. The oil and natural gas revenues of approximately $6.4 million generated by these increased production volumes was partially offset by the $1.9 million decrease in oil and natural gas revenues attributable primarily to the decline in the price we received for our natural gas production during the comparable periods. For the three months ended March 31, 2011, we received an average natural gas price of $3.65 per Mcf as compared to an average natural gas price of $4.76 per Mcf for the three months ended March 31, 2010.

Realized gain (loss) on derivatives. Our realized gain on derivatives increased by approximately $1.5 million to $1.8 million for the three months ended March 31, 2011 from $0.3 million for the three months ended March 31, 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 $1.31 per MMBtu hedged on all of our open natural gas costless collar contracts during the three months ended March 31, 2011 as compared to $0.20 per MMBtu hedged on all of our open natural gas costless collar contracts during the three months ended March 31, 2010.

 

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Unrealized gain (loss) on derivatives. Our unrealized loss on derivatives was $1.7 million for the three months ended March 31, 2011, compared to an unrealized gain of $6.1 million for the three months ended March 31, 2010. During the period from December 31, 2010 to March 31, 2011, the net fair value of our open natural gas costless collar contracts decreased from $4.1 million to $2.4 million, resulting in an unrealized loss on derivatives of $1.7 million for the three months ended March 31, 2011. This decrease in the net fair value of our open natural gas costless collar contracts was due to both an increase in the natural gas prices during the first quarter of 2011 and a decrease in the total number of open contracts at March 31, 2011 as compared to December 31, 2010. During the period from December 31, 2009 to March 31, 2010, the net fair value of our open natural gas costless collar contracts increased from $1.0 million to $7.1 million, resulting in an unrealized gain on derivatives of $6.1 million for the three months ended March 31, 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 fact that we had almost twice the 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

 

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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 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.

 

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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 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. When the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the estimated present value of after-tax future net cash flows from proved oil and natural gas reserves, discounted at 10%, such excess is charged to operations as a full-cost ceiling impairment in that reporting period.

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,
    Three Months Ended
March 31,
 
     2010     2009     2008     2011     2010  
                       (Unaudited)     (Unaudited)  
(In thousands, except expenses per Mcfe)       

Expenses:

          

Production taxes and marketing

   $ 1,982      $ 1,077      $ 1,639      $ 1,300      $ 267   

Lease operating

     5,284        4,725        4,667        1,605        1,332   

Depletion, depreciation and amortization

     15,596        10,743        12,127        7,111        3,362   

Accretion of asset retirement obligations

     155        137        91        39        38   

Full-cost ceiling impairment

            25,244        22,195        35,673          

General and administrative

     9,702        7,115        8,252        2,619        2,032   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

     32,719        49,041        48,972        48,347        7,031   

Operating income (loss)

     9,761        (24,752     (16,061     (34,467     8,554   

Other income (expense):

          

Net gain (loss) on asset sales and inventory impairment

     (224     (379     136,978                 

Interest and other income

     364        781        2,984        71        96   

Interest expense

     (3                   (106       
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

     137        402        139,962        (35     96   

Income (loss) before income taxes

     9,898        (24,350     123,901        (34,502     8,650   

Total income tax provision (benefit)

     3,521        (9,925     20,023        (6,906     2,974   

Net income (loss)

   $ 6,377      $ (14,425   $ 103,878      $ (27,596   $ 5,676   

Expenses per Mcfe:

          

Production taxes and marketing

   $ 0.23      $ 0.22      $ 0.50      $ 0.38      $ 0.14   

Lease operating

   $ 0.61      $ 0.94      $ 1.41      $ 0.47      $ 0.72   

Depletion, depreciation and amortization

   $ 1.81      $ 2.15      $ 3.67      $ 2.09      $ 1.82   

General and administrative

   $ 1.13      $ 1.42      $ 2.50      $ 0.77      $ 1.10   

Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2010

Production taxes and marketing. Our production taxes and marketing expenses increased by $1.0 million to $1.3 million, or an increase of almost four fold for the three months ended March 31, 2011, as compared to the three months ended March 31, 2010. The increase in our production taxes and marketing expenses was due primarily to the increases in both our oil and natural gas production and revenues by 84% and 49%, respectively, during the three months ended March 31, 2011 as compared to the three months ended March 31, 2010. Most of this increase was due to recently completed Haynesville shale wells, several of which were turned to sales or produced their first significant production volumes during the first quarter of 2011. Although we or our outside operating partners have applied for exemptions from initial production taxes on these wells, and although we expect these applications will be approved by the state of Louisiana, these wells had not yet been approved for production tax exemptions at March 31, 2011. Thus, we have paid and/or accrued for the associated production taxes on these wells during the first quarter 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 at that time.

 

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Lease operating expenses. Our lease operating expenses increased by $0.3 million to $1.6 million, or an increase of about 23%, for the three months ended March 31, 2011 as compared to the three months ended March 31, 2010. During these respective periods, however, our oil and natural gas production increased by 84% from 1.8 Bcfe to 3.4 Bcfe. As a result, our lease operating expenses per unit of production decreased by 35% to $0.47 per Mcfe for the three months ended March 31, 2011 as compared to $0.72 per Mcfe for the three months ended March 31, 2010. During the first quarter 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 $3.7 million to $7.1 million, or an increase of about 112%, for the three months ended March 31, 2011 as compared to the three months ended March 31, 2010. The increase in our depletion, depreciation and amortization expenses was due primarily to the increase of 84% in our oil and natural gas production from 1.8 Bcfe to 3.4 Bcfe during the respective time periods. A portion of this increase was also due to a 15% increase in our depletion, depreciation and amortization expenses on a unit-of-production basis from $1.82 per Mcfe for the three months ended March 31, 2010 to $2.09 per Mcfe for the three months ended March 31, 2011. This increase reflects increases in drilling and completion costs for wells drilled to the Haynesville shale during the past year. This increase is 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 $1,000 to approximately $39,000, or an increase of about 3%, for the three months ended March 31, 2011 as compared to the three months ended March 31, 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 operating 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 March 31, 2010. At March 31, 2011, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost 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.

General and administrative. Our general and administrative expenses increased by $0.6 million to $2.6 million, or an increase of about 30%, for the three months ended March 31, 2011 as compared to the three months ended March 31, 2010. The increase in our general and administrative expenses is due primarily to increased compensation expenses and increased accounting and legal expenses for the three months ended March 31, 2011 as compared to the three months ended March 31, 2010. As a result of our increased oil and natural gas production, however, our general and administrative expenses decreased by 30% on a unit-of-production basis to $0.77 per Mcfe for the three months ended March 31, 2011 as compared to $1.10 per Mcfe for the three months ended March 31, 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 three months ended March 31, 2011 or during the three months ended March 31, 2010.

 

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Interest expense. At March 31, 2011, we had borrowed $40.0 million under our revolving credit agreement to finance a portion of our working capital requirements and capital expenditures. At March 31, 2011, the interest rate on the outstanding borrowings was approximately 1.8%. We had no borrowings under the credit agreement at March 31, 2010, and as a result, we incurred no interest expense for the three months ended March 31, 2010.

Interest and other income. Our interest and other income decreased by approximately $25,000 to approximately $71,000, or a decrease of about 26%, for the three months ended March 31, 2011 as compared to the three months ended March 31, 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 receive interest income between the two periods. Our cash and cash equivalents and certificates of deposit decreased to $16.5 million at March 31, 2011 from $106.3 million at March 31, 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 $6.9 million for the three months ended March 31, 2011 as compared to a total income tax provision of approximately $3.0 million recorded for the three months ended March 31, 2010. The total income tax benefit or provision for both periods reflect only deferred income taxes. At March 31, 2011, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost 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 in the amount of approximately $5.3 million due to uncertainties regarding the future realization of our deferred tax assets. 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. For the three months ended March 31, 2010, the deferred income tax provision was consistent with our income before income taxes, which included approximately $6.1 million in unrealized hedging gains. We had a net loss for the three months ended March 31, 2011 and our effective tax rate for the three months ended March 31, 2010 was 34.38%.

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

 

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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 full-cost 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.

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.

 

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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.

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.

 

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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 full-cost 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 full-cost 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 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,

 

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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 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 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 July 31, 2011, we had a cash balance of $8.0 million.

 

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In March 2008, we entered into a credit agreement which was amended and restated in May 2011. Our credit agreement had a borrowing base of $80.0 million at June 30, 2011. At June 30, 2011, we had $60.0 million in borrowings outstanding and $375,000 in outstanding letters of credit issued pursuant to the credit agreement. Approximately $19.6 million remained available for additional borrowings. Any borrowings under the credit agreement are secured by mortgages on a significant portion of our oil and natural gas producing properties and by the equity interests of all our subsidiaries. At June 30, 2011, our outstanding borrowings bore interest at the rate of 2.1%. For more information regarding our revolving credit agreement, see “— Credit Agreement.”

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 is due and payable on December 31, 2011 and there is no penalty for prepayment. The term loan bears interest at an annual rate of 5% plus a Eurodollar-based rate, which equated to approximately 5.3% at June 30, 2011. For more information regarding our term loan, see “— Credit Agreement.”

We actively review acquisition opportunities on an ongoing basis. While we believe the net proceeds from this offering, together with our cash flows and future potential borrowings under our revolving credit agreement, will be adequate to fund our capital expenditure requirements and any acquisitions of interests and acreage for 2011 and 2012, funding for future acquisitions of interests and acreage or our future capital expenditure requirements may require additional sources of financing, which may not be available. See “Use of Proceeds.”

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

 

     Year Ended
December 31,
     Three Months Ended
March 31,
 
     2010     2009     2008      2011     2010  
(In thousands)                       (Unaudited)     (Unaudited)  

Net cash provided by operating activities

   $ 27,273      $ 1,791      $ 25,851       $ 12,732      $ 9,101   

Net cash provided by (used in) investing activities

     (147,334     (49,415     115,481         (35,024     (21,743

Net cash provided by financing activities

     36,891        1,086        419         15,693        31   
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Net change in cash and cash equivalents

   $ (83,170   $ (46,538   $ 141,751       $ (6,599   $ (12,611

Cash Flows Provided by Operating Activities

Net cash provided by operating activities increased by $3.6 million to $12.7 million for the three months ended March 31, 2011 as compared to net cash provided by operating activities of $9.1 million for the three months ended March 31, 2010. The increase in cash flows provided by operating activities reflects primarily an increase in our oil and natural gas production to 3.4 Bcfe from 1.8 Bcfe for the three months ended March 31, 2011 as compared to the three months ended March 31, 2010. The increase in cash flows was not proportionate with the increase in production due primarily to the decline in the price we received for our natural gas production in the comparable periods. Our accounts payable and accrued liabilities were approximately $35.8 million at March 31, 2011 as a result of operated horizontal wells that we were drilling and/or completing in the Haynesville and Eagle Ford shale plays during the first three months of 2011.

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,

 

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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. 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 $13.3 million to $35.0 million for the three months ended March 31, 2011 from $21.7 million for the three months ended March 31, 2010. This increase in net cash used in investing activities reflects primarily an increase of $11.9 million in our oil and natural gas properties capital expenditures for the three months ended March 31, 2011 as compared to the three months ended March 31, 2010. The increased oil and natural gas properties capital expenditures for the three months ended March 31, 2011 are primarily due to increased exploration and development expenditures associated with our operated and non-operated drilling and completion activities in the Eagle Ford and Haynesville plays, as compared to the three months ended March 31, 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 $104.1 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 acquisition of additional leasehold acreage in the Haynesville shale play, as well as exploration and development 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,

 

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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 $379.7 million in capital for acquisition, exploration and development activities in 2011 and 2012 as follows:

 

     Amount
(in  millions)
 

Exploration and development drilling and associated infrastructure

   $ 313.1   

Leasehold acquisition

     65.3   

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

     1.3   
  

 

 

 

Total

   $ 379.7   
  

 

 

 

For further information regarding our anticipated capital expenditure budgets in 2011 and 2012, see “Business—Overview.”

From January 1, 2011 through July 31, 2011, we spent approximately $84.2 million in capital expenditures (or 57% of our 2011 capital expenditures budget). From August 1, 2011 through December 31, 2011, we anticipate that our capital expenditures will be approximately $64.7 million.

Our 2011 and 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 and 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 Financing Activities

Net cash provided by financing activities was $15.7 million for the three months ended March 31, 2011 as compared to net cash provided by financing activities of $0.3 million for the three months ended March 31, 2010. This is due primarily to additional borrowings under our revolving credit agreement of $15.0 million to fund our working capital requirements during the three months ended March 31, 2011. 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.

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 revolving credit agreement. In addition, in April 2010, we repurchased 1,000,000 shares

 

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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 March 2008, we entered into a senior secured revolving credit agreement with Comerica Bank, N.A. to establish a secured revolving credit facility for a term of five years, and in May 2011 we entered into an amended and restated credit agreement with Comerica Bank, N.A. Any borrowings under the credit agreement are secured by mortgages on a significant portion of our oil and natural gas producing properties and by the equity interests of all our subsidiaries. In addition, all obligations under the credit agreement are guaranteed by our subsidiaries. The credit agreement matures in March 2013. As a result of the corporate reorganization, MRC Energy Company is the borrower under the credit agreement. Matador Resources Company has guaranteed MRC Energy Company’s obligations under the credit agreement and pledged its stock in MRC Energy Company as collateral.

The amount of the borrowings under the agreement is limited to the lesser of $150.0 million or the borrowing base, which is determined semi-annually on May 1 and November 1 by the lenders based primarily on estimates of our proved oil and natural gas reserves, but also on external factors, such as the bank’s lending policies and the bank’s estimates of future oil and natural gas prices, over which we have no control. At July 31, 2011, the borrowing base was $80.0 million. Both we and the bank may each request an unscheduled redetermination of the borrowing base one time during any 12-month period. In the event of a borrowing base increase, we pay a fee to the bank equal to 0.25% of the amount of the increase. 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 bank 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 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% or (ii) the prime rate for Comerica Bank then in effect. If we borrow

 

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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 1.00 minus the maximum rate during such interest calculation period at which Comerica Bank is required to maintain reserves on Euro-currency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System), plus (ii) an amount from 1.25% to 1.875% of such outstanding loan depending on the level of borrowings under the agreement. The interest period for Eurodollar borrowings may be one, two, three, six or twelve months as designated by us. An unused facility fee of 0.25% to 0.375%, depending on the unused portion of the borrowing base, is paid quarterly in arrears.

Key financial covenants under the credit agreement require us to maintain (1) a minimum current ratio, which is defined as consolidated total current assets plus 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.

Our revolving credit agreement contains various covenants that limit our ability to take certain actions, including, but not limited to, the following:

 

   

incur indebtedness;

 

   

enter into commodity hedging agreements;

 

   

declare or pay dividends, distributions or redemptions;

 

   

merge or consolidate; and

 

   

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

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, N.A. 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, N.A. 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

 

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statements within 45 days of the prior quarter end. We submitted both sets of financial statements to Comerica Bank, N.A. prior to this deadline.

At June 30, 2011, the borrowing base available for revolving borrowings was $80.0 million, and we had $60.0 million in borrowings outstanding under the credit agreement, an additional $375,000 in outstanding letters of credit issued pursuant to the credit agreement and approximately $19.6 million available for additional borrowings. At June 30, 2011, our outstanding revolving borrowings bore interest at the rate of approximately 2.1%. The outstanding revolving borrowings under our credit agreement mature in March 2013.

In addition to our revolving borrowings, in May 2011, we also 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 is due and payable on December 31, 2011 and there is no penalty for prepayment. The term loan bears interest at an annual rate of 5% plus a Eurodollar-based rate, which equated to approximately 5.3% at June 30, 2011, and while any principal and interest under the term loan is outstanding, the revolving borrowings under the credit agreement bear interest at the maximum annual rate of 1.875% plus a Eurodollar-based rate which equated to approximately 2.1% at June 30, 2011. We intend to repay the term loan in full with the net proceeds from this offering. We also intend to use a portion of the net proceeds from this offering to repay $10.0 million of our outstanding revolving borrowings.

Obligations and Commitments

We had the following material contractual obligations and commitments at June 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)

   $ 85,375       $ 25,375       $ 60,000       $       $   

Office lease

     6,243                 1,150         1,178         3,915   

Non-operated drilling commitments(2)

     4,000         4,000                           

Drilling rig contracts(3)

     5,500         5,500                           

Geological and geophysical contracts(4)

     404         404                           

Employee bonuses

     1,240                 1,240                   

Asset retirement obligations(5)

     3,809         335         442         822         2,210   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual cash obligations

   $ 106,571       $ 35,614       $ 62,832       $ 2,000       $ 6,125   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) At June 30, 2011, we had $60.0 million in revolving borrowings outstanding under our credit agreement, an additional $375,000 in outstanding letters of credit issued pursuant to the credit agreement and $25.0 million outstanding under the term loan. The term loan matures on December 31, 2011, and our borrowings under our revolving credit agreement mature in March 2013. These amounts do not include estimated interest on the obligations, because our revolving borrowings have short-term interest periods, and we are unable to determine what our borrowing costs may be in future periods.

 

(2) At June 30, 2011, we had outstanding commitments to participate in the drilling and completion of 46 gross and 1.3 net non-operated wells in the Haynesville shale play. Our working interest in these wells varies from 0.2% to 18.7%, and most of these wells were in progress at June 30, 2011. If all these wells are drilled and completed, we estimate that we will have a minimum remaining commitment for our participation in these wells of approximately $4.0 million at June 30, 2011, which we expect to incur within the next 12 months.

 

(3)

At July 31, 2011, we had entered into two drilling rig contracts to explore and develop our Eagle Ford acreage in south Texas. We anticipate that the first rig will begin drilling operations on our acreage in August 2011, with the second rig beginning drilling operations on our acreage in October 2011. Both contracts are for a term of six months. Should we elect to terminate both contracts prior to

 

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  initiating drilling operations, and if the drilling contractor were unable to secure work for both rigs prior to the end of their respective contract terms, we would incur an aggregate termination obligation of approximately $5.5 million.

 

(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.

 

(5) Asset retirement obligations at March 31, 2011.

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 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.

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 and conformance with SEC guidelines and generally accepted petroleum engineering and evaluation principles by independent petroleum engineers, except for certain interim periods as noted.

 

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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 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. Using 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. 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 production, selling or general corporate administrative activities. Exploration and development costs include dry-well costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil and natural gas reserves.

If the net capitalized costs of evaluated oil and natural gas properties less related deferred income taxes exceed the estimated present value of after-tax future net cash flows from proved oil and natural gas reserves, discounted at 10%, such excess is charged to operations as a full-cost ceiling impairment. A discount factor of 10% is used for purposes of computing the full-cost ceiling in accordance with SEC guidelines. The present value at 10% discount of future after-tax net cash flows is not intended to represent the replacement cost or fair market value of our oil and natural gas properties.

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 or more often if deemed necessary based upon changes in operating or economic conditions. This assessment includes consideration of the following

 

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factors, among others: the assignment 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 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. See “Compensation of Named Executive Officers — Stock Options.” 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.

Prior to the completion of this offering, we anticipate adopting the 2011 Long-Term Incentive Plan to be approved by shareholders. This plan will permit 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, 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 directors on the date of the grant. Depending on the terms of the restricted share grant, the fair value of the award may be recognized on the date of grant in our consolidated statement of operations, or in the case of a restricted share award that vests over time, the fair value of the award is measured on the date of grant and recognized on a straight-line basis over the vesting period.

Income Taxes

We file a United States federal income tax return and several state tax returns, a number of which remain open for examination. The tax years open for examination for the federal tax return are 2007, 2008, 2009 and 2010. The tax years open for examination by the state of Texas are 2008, 2009 and 2010. The tax years open for examination by the state of Louisiana are 2007, 2008, 2009 and 2010. At August 12, 2011, our 2007, 2008 and 2009 income and franchise tax returns were under examination by the state of Louisiana. The tax years open for examination by the state of New Mexico are 2008, 2009 and 2010.

 

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We account for income taxes using the asset and liability approach for financial accounting and reporting. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition.

We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority.

We have evaluated all tax positions for which the statute of limitations remained open, and we believe that the material positions taken would more likely than not be sustained by examination. When necessary, we would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on our consolidated statement of operations. At December 31, 2010, 2009 and 2008, we did not record any interest or penalties related to income tax.

Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue

Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the SEC has recently adopted rules which allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this prospectus. The SEC’s revised rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated at least annually and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, revenues, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial position, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

Recent Accounting Pronouncements

Subsequent Events. We incorporate the accounting and disclosure requirements for subsequent events in our financial statements. In accordance with GAAP, new terminology was introduced recently which

 

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defines the date through which management must evaluate subsequent events and lists the circumstances under which an entity must recognize and disclose events or transactions occurring after the balance sheet date. We adopted this guidance at December 31, 2009.

Oil and Natural Gas Reserves Reporting Requirements. In January 2009, the SEC issued The Modernization of Oil and Gas Reporting, Final Rule. In January 2010, the Financial Accounting Standards Board, or FASB, amended Topic 932, Extractive Activities — Oil and Gas to align with this rule. The changes are designed to modernize and update the oil and natural gas disclosure requirements to align them with current practices and changes in technology. The new rules made a number of important changes including the following: (i) expanded the definition of oil and natural gas producing activities to include the extraction of saleable hydrocarbons from oil sands, shale, coalbeds or other nonrenewable natural resources, (ii) amended the required price for estimating economic quantities for year-end reserves reporting to be the unweighted, arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period, rather than the year-end price and (iii) permitted proved reserves to be claimed beyond those development spacing areas that are immediately adjacent to developed spacing areas if it can be established with reasonable certainty that these reserves are economically producible. At December 31, 2009, we adopted the provisions of this new rule, and we have applied this new guidance for the reserves estimates shown for December 31, 2010 and 2009 and March 31, 2011 included herein.

Derivative Financial Instruments. At December 31, 2008, we adopted new guidance to provide qualitative disclosures about our objectives and strategies for using derivative financial instruments and to provide a tabular presentation of quantitative information for derivatives designated as hedges, hedged items and other derivatives. This new guidance was effective for annual financial periods beginning after November 15, 2008. As its only requirement is to enhance disclosures, the new guidance had no material impact on our consolidated financial statements.

Fair Value. In May 2011, the FASB issued Accounting Standards Update, or ASU, 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS, or ASU 2011-04. ASU 2011-04 amends Accounting Standards Codification, or ASC, 820, Fair Value Measurements, or ASC 820, providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurements and expands the ASC 820 disclosure requirements, particularly for Level 3 fair value measurements. The adoption of ASU 2011-04 is not expected to have a material impact on our consolidated financial statements, but may require certain additional disclosures. The amendments in ASU 2011-04 are to be applied prospectively. For public entities, the amendments are effective during interim and annual periods beginning after December 15, 2011.

In January 2010, the FASB issued authoritative guidance to update certain disclosure requirements and added two new disclosure requirements related to fair value measurements. The guidance requires a gross presentation of activities within the Level 3 roll forward and adds a new requirement to disclose details of significant transfers in and out of Level 1 and 2 measurements and the reasons for the transfers. The new disclosures are required for all companies that are required to provide disclosures about recurring and non-recurring fair value measurements, and are effective the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. We adopted the first portion of this guidance beginning January 1, 2010. We do not expect the adoption of this new guidance to have a significant impact on our financial position, results of operations or cash flows.

 

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In September 2006, the FASB issued authoritative guidance for using fair value to measure assets and liabilities. This guidance applies whenever other standards require or permit assets or liabilities to be measured at fair value, but it does not expand the use of fair value in any new circumstances. In February 2009, the FASB delayed the effective date by one year for non-financial assets and liabilities. We adopted this guidance effective January 1, 2008, but delayed guidance relating to non-financial assets and liabilities until January 1, 2009. The adoption of this guidance did not have a significant impact on our financial position, results of operations or cash flows.

In February 2007, the FASB issued authoritative guidance permitting entities to choose to