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EX-8.1 - EX-8.1 - Enduro Resource Partners LLCd82176a3exv8w1.htm
EX-5.1 - EX-5.1 - Enduro Resource Partners LLCd82176a3exv5w1.htm
EX-23.1 - EX-23.1 - Enduro Resource Partners LLCd82176a3exv23w1.htm
EX-23.5 - EX-23.5 - Enduro Resource Partners LLCd82176a3exv23w5.htm
EX-23.2 - EX-23.2 - Enduro Resource Partners LLCd82176a3exv23w2.htm
Table of Contents

As filed with the Securities and Exchange Commission on July 29, 2011
Registration No. 333-174225
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
Amendment No. 3
to
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
 
     
Enduro Royalty Trust   Enduro Resource Partners LLC
(Exact Name of co-registrant as specified in its charter)   (Exact Name of co-registrant as specified in its charter)
Delaware   Delaware
(State or other jurisdiction of incorporation or organization)   (State or other jurisdiction of incorporation or organization)
1311   1311
(Primary Standard Industrial Classification Code Number)   (Primary Standard Industrial Classification Code Number)
45-6259461   27-2036288
(I.R.S. Employer Identification No.)   (I.R.S. Employer Identification No.)
919 Congress Avenue, Suite 500
Austin, Texas 78701
(512) 236-6599
  777 Main Street, Suite 800
Fort Worth, Texas 76102
(817) 744-8200
Attention: John W. Arms
(Address, including zip code, and telephone number, including
area code, of co-registrant’s Principal Executive Offices)
  (Address, including zip code, and telephone number, including
area code, of co-registrant’s Principal Executive Offices)
 
     
The Bank of New York Mellon Trust
Company, N.A., Trustee
919 Congress Avenue, Suite 500
Austin, Texas 78701
(512) 236-6599
Attention: Michael J. Ulrich
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
  Jon S. Brumley
  777 Main Street, Suite 800
   Fort Worth, Texas 76102
(817) 744-8200
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
 
 
 
 
Copies to:
     
Sean T. Wheeler
Latham & Watkins LLP
717 Texas Avenue, Suite 1600
Houston, Texas 77002
(713) 546-5400
  Joshua Davidson
Gerald M. Spedale
Baker Botts L.L.P.
910 Louisiana, Suite 3200
Houston, Texas 77002
(713) 229-1234
 
 
 
 
Approximate date of commencement of proposed sale to the public:  As soon as practicable after this Registration Statement becomes effective.
 
 
 
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.  o
 
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.  o
 
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.  o
 
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.  o
 
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 o Accelerated filer o Non-accelerated filer þ Smaller reporting company o
(Do not check if a smaller reporting company)
 
 
 
 
The co-registrants hereby amend this Registration Statement on such date or dates as may be necessary to delay its effective date until the co-registrants 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 Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
 


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The information in this prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.
 
Subject to Completion dated July 29, 2011
 
PROSPECTUS
 
 
13,200,000 Trust Units
 
(ENDURO ROYALTY TRUST LOGO)
 
 
This is the initial public offering of units of beneficial interest in Enduro Royalty Trust, or the “trust.” Enduro Sponsor (as defined in the “Prospectus Summary”) has formed the trust and, immediately prior to the closing of this offering, will convey, or cause to be conveyed, a net profits interest in oil and natural gas properties (the “Net Profits Interest”) to the trust in exchange for 33,000,000 trust units. Enduro Sponsor is offering 13,200,000 trust units to be sold in this offering and will receive all of the proceeds derived therefrom. After the offering, Enduro Sponsor will own 19,800,000 trust units, or 17,820,000 trust units if the underwriters exercise their option to purchase additional trust units from Enduro Sponsor. No public market currently exists for the trust units. Enduro Sponsor is a privately-held limited liability company engaged in the production and development of oil and natural gas from properties located in Texas, Louisiana and New Mexico.
 
The trust units have been approved for listing on the New York Stock Exchange, subject to official notice of issuance, under the symbol “NDRO.”
 
Enduro Sponsor expects that the public offering price will be between $      and $      per trust unit.
 
The trust units.  Trust units are equity securities of the trust and represent undivided beneficial interests in the trust assets. They do not represent any interest in Enduro Sponsor.
 
The trust.  The trust will own the Net Profits Interest, which represents the right to receive 80% of the net profits from the sale of production from oil and natural gas properties in Texas, Louisiana and New Mexico, which are referred to as the “Underlying Properties,” held by Enduro Sponsor as of the date of the conveyance of the Net Profits Interest to the trust. Enduro Sponsor will retain the remaining 20% of the net profits from the sale of production from the Underlying Properties as of the date of the conveyance.
 
The trust unitholders.  As a trust unitholder, you will receive monthly distributions of cash from the proceeds that the trust receives from Enduro Sponsor pursuant to the Net Profits Interest. The trust’s ability to pay monthly cash distributions will depend on its receipt of net profits attributable to the Net Profits Interest, which will depend upon, among other things, volumes produced, wellhead prices, price differentials, production and development costs, potential reductions or suspensions of production and the amount and timing of trust administrative expenses.
 
Investing in the trust units involves a high degree of risk. Please read “Risk Factors” beginning on page 17 of this prospectus.
 
 
 
 
                 
    Per Trust Unit   Total
 
Price to the public
  $               $            
Underwriting discounts and commissions(1)
  $       $    
Proceeds, before expenses, to Enduro Sponsor
  $       $  
 
 
(1) Excludes a structuring fee of 0.5% of the gross proceeds of the offering payable to Barclays Capital Inc. by Enduro Sponsor for the evaluation, analysis and structuring of the trust.
 
Enduro Sponsor has granted the underwriters a 30-day option to purchase up to an additional 1,980,000 trust units from it on the same terms and conditions set forth above if the underwriters sell more than 13,200,000 trust units in this offering.
 
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
 
Barclays Capital, on behalf of the underwriters, expects to deliver the trust units on or about          , 2011.
 
 
Barclays Capital Citigroup Goldman, Sachs & Co. RBC Capital Markets Wells Fargo Securities
 
 
 
 
J.P. Morgan        Baird           Morgan Keegan           Stifel Nicolaus Weisel           Wunderlich Securities
 
 
 
 
Prospectus dated          , 2011


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(MAP)


 

 
TABLE OF CONTENTS
 
     
  1
  17
  34
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  44
  45
  52
  79
  83
  88
  91
  93
  100
  101
  102
  103
  108
  108
  108
  109
  F-1
  ENDURO-1
  ENDURO F-1
  ANNEX A-1-1
  ANNEX A-2-1
  ANNEX A-3-1
  ANNEX B-1
  ANNEX C-1
 EX-5.1
 EX-8.1
 EX-23.1
 EX-23.2
 EX-23.5
 
Important Notice About Information in This Prospectus
 
Enduro Sponsor and the trust have not, and the underwriters have not, authorized anyone to provide you with additional or different information. If anyone provides you with additional, different or inconsistent information, you should not rely on it. This prospectus is not an offer to sell or a solicitation of an offer to buy the trust units in any jurisdiction where such offer and sale would be unlawful. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this document. The trust’s business, financial condition, results of operations and prospects may have changed since such date.


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This summary highlights information contained elsewhere in this prospectus. To understand this offering fully, you should read the entire prospectus carefully, including the risk factors and the financial statements and notes to those statements. Unless otherwise indicated, all information in this prospectus assumes (a) an initial public offering price of $      per trust unit and (b) no exercise of the underwriters’ option to purchase additional trust units.
 
Unless the context otherwise requires, as used in this prospectus, (i) “Predecessor Properties” refers to the East Texas and North Louisiana oil and natural gas properties acquired by Enduro Resource Partners LLC from Denbury Resources Inc. in December 2010, (ii) “Predecessor” refers to Enduro Resource Partners LLC after giving effect to the acquisition of the Predecessor Properties but without giving effect to the acquisition of the Acquired Properties, (iii) the “Acquired Properties” refers to the Permian Basin oil and natural gas properties acquired by the Predecessor from Samson Investment Company in January 2011 and from ConocoPhillips Company in February 2011, (iv) when discussing the assets, operations or financial condition and results of operations of Enduro Sponsor, unless otherwise indicated, “Enduro Sponsor” refers to the Predecessor after giving effect to the acquisition of the Acquired Properties, and when discussing oil and natural gas reserve information of Enduro Sponsor, refers to the estimated proved oil and natural gas reserves for the Predecessor after giving effect to the acquisition of the Acquired Properties as reflected in the reserve reports (as defined below) and (v) “Underlying Properties” refers to the portion of the Predecessor Properties in which the trust has a Net Profits Interest (as defined below) and the Acquired Properties after deducting all royalties and other burdens on production thereon as of the date of the conveyance of the Net Profits Interest to the trust. For more information on the Underlying Properties and the acquisition of the Acquired Properties by the Predecessor, please see “The Underlying Properties” and “Information about Enduro Resource Partners LLC (Enduro Sponsor),” respectively.
 
Cawley, Gillespie & Associates, Inc., referred to in this prospectus as “Cawley Gillespie,” an independent engineering firm, provided the estimates of proved oil and natural gas reserves as of December 31, 2010 included in this prospectus. These estimates are contained in summaries prepared by Cawley Gillespie of its reserve reports as of December 31, 2010 for the Predecessor Properties, Samson Permian Basin properties, ConocoPhillips Permian Basin properties, the Underlying Properties and the Net Profits Interest. These summaries are located at the back of this prospectus in Annexes A-1, A-2, A-3, B and C and are collectively referred to in this prospectus as the “reserve reports.” You will find definitions for terms relating to the oil and natural gas business in “Glossary of Certain Oil and Natural Gas Terms.”
 
Enduro Royalty Trust
 
Enduro Royalty Trust is a Delaware statutory trust formed in May 2011 by Enduro Sponsor to own a net profits interest representing the right to receive 80% of the net profits from the sale of oil and natural gas production from certain properties in the states of Texas, Louisiana and New Mexico held by Enduro Sponsor as of the date of the conveyance of the net profits interest to the trust. The conveyed interest is referred to as the “Net Profits Interest.” The trust will make monthly cash distributions of all of its monthly cash receipts, after deduction of fees and expenses for the administration of the trust, to holders of its trust units as of the applicable record date (generally the 15th day of each calendar month) on or before the 10th business day after the record date. The Net Profits Interest will be entitled to a share of the profits from production occurring on or after May 1, 2011. The trust is not subject to any pre-set termination provisions based on a maximum volume of oil or natural gas to be produced or the passage of time.
 
The Underlying Properties were acquired in three separate transactions and are located in two different geographic regions: the Permian Basin and East Texas/North Louisiana. As of December 31, 2010, approximately 99.3% of the wells on the Underlying Properties were operated by third party oil and natural gas companies with significant experience in the development and operation of oil and


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natural gas properties (the “Third Party Operators”). The following table summarizes certain information regarding the proved reserves and production associated with the Underlying Properties as of and for the period indicated. The reserve reports were prepared by Cawley Gillespie in accordance with criteria established by the Securities and Exchange Commission (the “SEC”). For information regarding proved reserves and production related to the Net Profits Interest, please see “The Underlying Properties.”
 
                                                 
    Underlying Properties  
                            Average Daily Net
       
    As of December 31, 2010     Production For Year
       
    Proved Reserves(1)     Ended December 31,
    As of December 31,
 
    PV-10
    Total
          % Proved Developed
    2010
    2010
 
Operating Area
  Value(2)     (MBoe)(3)     % Oil     Reserves     (Boe per day)     R/P Ratio(4)  
    (In thousands)                                
 
Permian Basin
  $ 279,975       16,321       78 %     96 %     3,526       13  
East Texas/North Louisiana
    69,557       10,743       0 %     48 %     2,321       13  
                                                 
Total
  $ 349,532       27,064       47 %     76 %     5,847       13  
                                                 
 
 
(1) In accordance with the rules and regulations promulgated by the SEC, the proved reserves presented above were determined using the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from January 1, 2010 through December 31, 2010, without giving effect to any hedge transactions, and were held constant for the life of the properties. This yielded a price for oil of $79.43 per Bbl and a price for natural gas of $4.37 per MMBtu.
 
(2) PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted using an annual discount rate of 10%, calculated without deducting future income taxes. Standardized measure of discounted future net cash flows is calculated the same as PV-10 except that it deducts future income taxes and future abandonment costs. Because Enduro Sponsor bears no federal income tax expense and taxable income is passed through to the unitholders of the trust, no provision for federal or state income taxes is included in the reserve reports. PV-10 may not be considered a generally accepted accounting principle (“GAAP”) financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. The pre-tax PV-10 value and the standardized measure of discounted future net cash flows do not purport to present the fair value of the oil and natural gas reserves attributable to the Underlying Properties.
 
(3) Oil equivalents in the table are the sum of the Bbls of oil and the Boe of the stated Mcfs of natural gas, calculated on the basis that six Mcfs of natural gas are the energy equivalent of one Bbl of oil.
 
(4) The R/P ratio, or the reserves-to-production ratio, is a measure of the number of years that a specified reserve base could support a fixed amount of production. This ratio is calculated by dividing total estimated proved reserves of the subject properties at the end of a period by annual total production for the prior 12 months. Because production rates naturally decline over time, the R/P ratio is not a useful estimate of how long properties should economically produce. Based on the reserve reports, economic production from the Underlying Properties is expected for at least 50 more years.


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The following graph shows estimated annual production of total proved reserves attributable to the Underlying Properties based upon the pricing and other assumptions set forth in the reserve reports. This graph presents the total proved volumes as reflected in the reserve reports broken down by two reserve categories (proved developed and proved undeveloped reserves) as of December 31, 2010.
 
(BAR CHART)
 
The following table sets forth the five largest fields in the Underlying Properties, the operator(s) of each field and the PV-10 value represented by each field:
 
                     
              % of Total
 
        PV-10 at
    PV-10 at
 
Field Name
  Operator   December 31, 2010     December 31, 2010  
        (In thousands)        
 
Elm Grove Field
  Petrohawk Energy Corporation(1), J-W Operating, Questar Corporation   $ 54,591       16 %
North Monument Grayburg Unit
  Apache Corporation     42,989       12 %
North Central Levelland Unit
  Apache Corporation     39,208       11 %
North Cowden Unit
  Occidental Permian Ltd.     32,563       9 %
Yates Field Unit
  Kinder Morgan Inc.     18,052       5 %
                     
Total
      $ 187,403       53 %
 
 
(1) On July 14, 2011, BHP Billiton Ltd. announced it had entered into an agreement to acquire Petrohawk. Enduro Sponsor does not believe that the consummation of the acquisition will significantly affect Petrohawk’s operations on the Underlying Properties.
 
Key Investment Considerations
 
The following are some key investment considerations related to the Underlying Properties, the Net Profits Interest and the trust units:
 
  •      Mature oil base combined with significant production and inventories of low risk natural gas locations. The Underlying Properties in the Permian Basin region include multiple


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  mature oil fields currently using secondary and tertiary recovery methods. These fields typically are characterized by mature long-lived production profiles. Many of the Underlying Properties in the Permian Basin currently under waterflood have CO2 recovery potential, which could increase the ultimate oil recovered from these fields. The Underlying Properties located in the East Texas/North Louisiana region have significant natural gas production and near-term growth potential stemming primarily from the development of the Haynesville Shale and the horizontal Cotton Valley plays. Future increases in natural gas prices could accelerate development activity in this region, thereby increasing cash flows.
 
  •      Substantial proved developed reserves.  Proved developed reserves are the most valuable and lowest risk category of reserves because their production requires no significant future development expenses. As of December 31, 2010, approximately 75% of the volumes and 90% of the PV-10 value of the proved reserves associated with the Underlying Properties were attributed to proved developed reserves.
 
  •      Additional development opportunities.  Enduro Sponsor believes that the Underlying Properties are likely to offer economic development opportunities in the future that are not reflected in existing proved reserves and that could significantly increase future reserves and production. In the Permian Basin region, future increases in estimated oil recovery factors may increase reserves and production. Such increases in recovery factors may occur through, among other means, the implementation of additional enhanced recovery techniques, infill drilling and production outperformance. Examples of potential development opportunities not included in proved reserves in the East Texas/North Louisiana region include increased density drilling, refracs and development of prospective formations such as the Bossier Shale and Smackover, among others.
 
  •      Location in areas with significant histories of oil and natural gas production.  Long producing histories in the Permian Basin and East Texas/North Louisiana regions provide well established production profiles which increase certainty of production estimates. These regions also have significant access to oilfield services and pipeline takeaway infrastructure. In addition, Enduro Sponsor believes that operating risk is generally lower in regions accustomed to oil and natural gas production.
 
  •      Leading third party operators.  In the Permian Basin region, approximately 70% of the PV-10 value of the proved reserves is operated by Occidental Petroleum, Apache Corporation or Kinder Morgan, all of whom are among the top 10 producers in the basin by volume. These operators also have many years of experience in maximizing production response from mature oil and natural gas fields through enhanced recovery techniques. In the East Texas/North Louisiana region, approximately 85% of the PV-10 value of proved reserves is operated by Petrohawk Energy Corporation and EXCO Resources, Inc. These companies are two of the most active operators in the Haynesville Shale play and have significant operating experience in the region.
 
  •      Downside commodity price protection.  To mitigate the negative effects of a possible decline in oil and natural gas prices on distributable income to the trust, Enduro Sponsor has entered into hedge contracts with respect to approximately 69%, 70% and 57% of expected oil and natural gas production for 2011, 2012 and 2013, respectively, from the total proved reserves attributable to the Underlying Properties in the reserve reports. These hedge contracts include a combination of fixed price swaps, collars and floors to protect the trust’s downside, while still allowing the trust to participate in increasing oil and natural gas markets. After December 31, 2013, none of the production attributable to the Underlying Properties will be hedged.
 
  •      High Operating Margins.  The Underlying Properties have historically generated substantial operating margins. Lease operating expenses and property and other taxes on the Underlying Properties averaged $15.93 per Boe during the past three years. During the


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  same period, the sales price for oil and natural gas averaged $52.65 per Boe, providing an operating margin of $36.72 per Boe, or 70%.
 
  •      Aligned interests of sponsor.  Immediately following the closing of this offering, Enduro Sponsor will have an effective ownership of approximately 68% of the net profits attributable to the sale of oil and natural gas produced from the Underlying Properties, including its retained 20% interest in the net profits from the sale of production from the Underlying Properties and its ownership of approximately 60% of the trust units.
 
Formation Transactions
 
At or prior to the closing of this offering, the following transactions, which are referred to herein as the “formation transactions,” will occur:
 
  •      Enduro Sponsor will convey, or cause to be conveyed, to the trust the Net Profits Interest effective as of May 1, 2011 in exchange for 33,000,000 trust units in the aggregate, representing all of the outstanding trust units of the trust.
 
  •      Enduro Sponsor will sell 13,200,000 trust units offered hereby, representing an approximate 40% interest in the trust. Enduro Sponsor will also make available during the 30-day option period up to 1,980,000 trust units for the underwriters to purchase at the initial offering price to cover over-allotments. Enduro Sponsor intends to use the proceeds of the offering as disclosed under “Use of Proceeds.”
 
Structure of the Trust
 
The following chart shows the relationship of Enduro Sponsor, the trust and the public trust unitholders after the closing of this offering.
 
(FLOw CHART)
 
Risk Factors
 
An investment in the trust units involves risks associated with fluctuations in energy commodity prices, the operation of the Underlying Properties, certain regulatory and legal matters, the structure of the trust and the tax characteristics of the trust units. Please read carefully the risks described under “Risk Factors” on page 17 of this prospectus.
 
  •      Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the trust and cash distributions to trust unitholders.


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  •      Estimates of future cash distributions to trust unitholders are based on assumptions that are inherently subjective.
 
  •      Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the trust and the value of the trust units.
 
  •      The Third Party Operators are the operators of approximately 99.3% of the wells on the Underlying Properties and, therefore, Enduro Sponsor is not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.
 
  •      Developing oil and natural gas wells and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect future production from the Underlying Properties. Any delays, reductions or cancellations in development and producing activities could decrease revenues that are available for distribution to trust unitholders.
 
  •      The trust is passive in nature and neither the trust nor the trust unitholders will have any ability to influence Enduro Sponsor or control the operations or development of the Underlying Properties.
 
  •      Shortages of equipment, services and qualified personnel could increase costs of developing and operating the Underlying Properties and result in a reduction in the amount of cash available for distribution to the trust unitholders.
 
  •      The trust units may lose value as a result of title deficiencies with respect to the Underlying Properties.
 
  •      Enduro Sponsor may transfer all or a portion of the Underlying Properties at any time without trust unitholder consent, subject to specified limitations.
 
  •      The reserves attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production. Therefore, proceeds to the trust and cash distributions to trust unitholders will decrease over time.
 
  •      An increase in the differential between the price realized by Enduro Sponsor for oil or natural gas produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the profits to the trust and, therefore, the cash distributions by the trust and the value of trust units.
 
  •      The amount of cash available for distribution by the trust will be reduced by the amount of any costs and expenses related to the Underlying Properties and other costs and expenses incurred by the trust.
 
  •      The generation of profits for distribution by the trust depends in part on access to and operation of gathering, transportation and processing facilities. Any limitation in the availability of those facilities could interfere with sales of oil and natural gas production from the Underlying Properties.
 
  •      The trustee must, under certain circumstances, sell the Net Profits Interest and dissolve the trust prior to the expected termination of the trust. As a result, trust unitholders may not recover their investment.
 
  •      Enduro Sponsor may sell trust units in the public or private markets, and such sales could have an adverse impact on the trading price of the trust units.
 
  •      There has been no public market for the trust units.


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  •      The trading price for the trust units may not reflect the value of the Net Profits Interest held by the trust.
 
  •      Conflicts of interest could arise between Enduro Sponsor and its affiliates, on the one hand, and the trust and the trust unitholders, on the other hand.
 
  •      The trust is managed by a trustee who cannot be replaced except by a majority vote of the trust unitholders at a special meeting, which may make it difficult for trust unitholders to remove or replace the trustee.
 
  •      Trust unitholders have limited ability to enforce provisions of the Net Profits Interest, and Enduro Sponsor’s liability to the trust is limited.
 
  •      Courts outside of Delaware may not recognize the limited liability of the trust unitholders provided under Delaware law.
 
  •      The operations of the Underlying Properties are subject to environmental laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or result in significant costs and liabilities, which could reduce the amount of cash available for distribution to trust unitholders.
 
  •      The operations of the Underlying Properties are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or expose the operator to significant liabilities, which could reduce the amount of cash available for distribution to trust unitholders.
 
  •      Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that the operators produce while the physical effects of climate change could disrupt their production and cause them to incur significant costs in preparing for or responding to those effects.
 
  •      Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect the services of the operators of the Underlying Properties.
 
  •      The bankruptcy of Enduro Sponsor or any of the Third Party Operators could impede the operation of the wells and the development of the proved undeveloped reserves.
 
  •      In the event of the bankruptcy of Enduro Sponsor, if a court held that the Net Profits Interest was part of the bankruptcy estate, the trust may be treated as an unsecured creditor with respect to the Net Profits Interest attributable to properties in Louisiana and New Mexico.
 
  •      Adverse developments in Texas, Louisiana or New Mexico could adversely impact the results of operations and cash flows of the Underlying Properties and reduce the amount of cash available for distributions to trust unitholders.
 
  •      The receipt of payments by Enduro Sponsor based on the hedge contracts depends upon the financial position of the hedge contract counterparties. A default by any of the hedge contract counterparties could reduce the amount of cash available for distribution to the trust unitholders.
 
  •      The tax treatment of an investment in trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis.
 
  •      The trust has not requested a ruling from the Internal Revenue Service (the “IRS”) regarding the tax treatment of the trust. If the IRS were to determine (and be sustained in that determination) that the trust is not a “grantor trust” for federal income tax purposes,


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  the trust could be subject to more complex and costly tax reporting requirements that could reduce the amount of cash available for distribution to trust unitholders.
 
  •      Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.
 
  •      You will be required to pay taxes on your share of the trust’s income even if you do not receive any cash distributions from the trust.
 
  •      A portion of any tax gain on the disposition of the trust units could be taxed as ordinary income.
 
  •      The trust will allocate its items of income, gain, loss and deduction between transferors and transferees of the trust units each month based upon the ownership of the trust units on the monthly record date, instead of on the basis of the date a particular trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the trust unitholders.
 
Summary Unaudited Pro Forma Combined Financial and Operating Data of the Underlying Properties and Unaudited Pro Forma Distributable Income of the Trust
 
Unaudited Pro Forma Combined Financial Data of the Underlying Properties
 
The summary unaudited pro forma combined financial data presented below should be read in conjunction with “The Underlying Properties — Unaudited Pro Forma Combined Financial and Operating Data of the Underlying Properties,” “The Underlying Properties — Discussion and Analysis of Pro Forma Combined Historical Results of the Underlying Properties” and the accompanying financial statements and related notes included elsewhere in this prospectus. The following table sets forth the combined revenues, direct operating expenses and the excess of revenues over direct operating expenses of all the Underlying Properties as if they had been owned by Enduro Sponsor as of January 1, 2010. The summary unaudited pro forma combined financial data have been derived from the unaudited pro forma statements of historical revenues and direct operating expenses of the Underlying Properties included elsewhere in this prospectus.
 
                 
    Three Months Ended
    Year Ended
 
    March 31, 2011     December 31, 2010  
    (In thousands)
 
    (Unaudited)  
 
Revenues:
               
Oil
  $ 20,150     $ 70,033  
Natural gas
    7,262       33,787  
                 
Total revenues
  $ 27,412     $ 103,820  
                 
Direct operating expenses:
               
Lease operating
  $ 6,185     $ 24,579  
Gathering and processing
    489       1,977  
Production and other taxes
    2,005       8,069  
                 
Total direct operating expenses
  $ 8,679     $ 34,625  
                 
Excess of revenues over direct operating expenses
  $ 18,733     $ 69,195  
                 
 
Unaudited Pro Forma Distributable Income of the Trust
 
The table below outlines the calculation of pro forma distributable income from the Net Profits Interest for the three months ended March 31, 2011 and for 2010 based on the excess of revenues over direct operating expenses of the Underlying Properties for the three months ended March 31, 2011 and for the year ended December 31, 2010, respectively, set forth above. The table below should be read in


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conjunction with the unaudited pro forma financial information of the trust included elsewhere in this prospectus. The pro forma amounts below do not purport to present cash available for distribution by the trust to trust unitholders had the formation transactions contemplated actually occurred on January 1, 2010. In addition, cash available for distribution by the trust will be calculated based upon actual cash receipts of the trust during the applicable month, while the unaudited pro forma available cash calculation has been prepared using a modified cash basis of accounting. Please refer to the unaudited pro forma financial information for the trust included elsewhere in this prospectus for more information. As a result, you should view the amount of unaudited pro forma available cash only as a general indication of the amount of cash available for distribution by the trust for the three months ended March 31, 2011 and for the year ended December 31, 2010.
 
                 
    Three Months Ended
    Year Ended
 
    March 31, 2011     December 31, 2010  
    (In thousands, except per unit data)
 
    (Unaudited)  
 
Excess of revenues over direct operating expenses
  $ 18,733     $ 69,195  
Less development expenses
    12,105       37,036  
                 
Excess of revenues over direct operating expenses and development expenses
  $ 6,628     $ 32,159  
Times Net Profits Interest
    80 %     80 %
                 
Income from Net Profits Interest
  $ 5,302     $ 25,727  
                 
Pro forma adjustments:
               
Less estimated trust general and administrative expenses
  $ 213     $ 850  
                 
Distributable income
  $ 5,089     $ 24,877  
                 
Distributable income per trust unit
  $ 0.15     $ 0.75  
                 
 
Pro Forma Combined Operating Data of the Underlying Properties
 
The following table provides the pro forma combined oil and natural gas sales volumes, average sales prices, average costs per Boe and capital expenditures for the Underlying Properties for the three months ended March 31, 2011 and 2010 and for the years ended December 31, 2010, 2009


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and 2008. This pro forma combined operating data includes the effect of the Acquired Properties for all periods presented.
 
                                         
    Three Months Ended
       
    March 31,     Year Ended December 31,  
    2011     2010     2010     2009     2008  
                (Unaudited)              
 
Operating Data:
                                       
Sales volumes:
                                       
Oil (MBbls)
    230       239       939       1,016       1,084  
Natural gas (MMcf)
    1,619       1,768       7,171       8,455       8,868  
Total sales (MBoe)
    500       534       2,134       2,425       2,562  
Average sales prices:
                                       
Oil (per Bbl)
  $ 87.61     $ 72.61     $ 74.58     $ 54.44     $ 98.52  
Natural gas (per Mcf)
    4.49       5.56       4.71       3.91       8.57  
Average costs per Boe:
                                       
Lease operating
  $ 12.37     $ 11.62     $ 11.52     $ 10.65     $ 11.45  
Gathering and processing
    0.98       0.79       0.93       0.78       1.18  
Production and other taxes
    4.01       3.58       3.78       3.10       4.38  
Capital expenditures (in thousands):
                                       
Property development costs
  $ 12,105     $ 1,781     $ 37,036     $ 18,532     $ 65,571  
 
Summary Historical and Unaudited Pro Forma Financial Data of Enduro Sponsor
 
The summary historical audited financial data of the Predecessor as of and for the year ended December 31, 2010 have been derived from the audited financial statements of the Predecessor included elsewhere in this prospectus. Operations of the Predecessor Properties are deemed to be the “predecessor” of Enduro Sponsor and recorded transactions are shown separately based on the ownership of the Predecessor Properties. Encore Acquisition Company (“EAC”) owned the Predecessor Properties prior to March 9, 2010, at which time Denbury Resources Inc. acquired the properties in connection with its acquisition of EAC. Enduro Sponsor then acquired the Predecessor Properties on December 1, 2010. Accordingly, the audited financial statements of the Predecessor as of and for the year ended December 31, 2010 are presented for (i) “Predecessor-EAC” for the period from January 1, 2010 through March 8, 2010; (ii) “Predecessor-DNR” for the period from March 9, 2010 through November 30, 2010 and (iii) “Enduro Sponsor” for the period from Enduro Sponsor’s inception (March 3, 2010) through December 31, 2010.
 
The summary historical unaudited financial data of Enduro Sponsor as of March 31, 2011 and 2010 and for the three-month period ended March 31, 2011 and 2010 have been derived from Enduro Sponsor’s unaudited interim financial statements. The unaudited financial statements were prepared on a basis consistent with the audited statements and, in the opinion of Enduro Sponsor’s management, include all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the results of Enduro Sponsor for the periods presented.
 
The summary unaudited pro forma financial data as of and for the three months ended March 31, 2011 and for the year ended December 31, 2010 set forth in the following table has been derived from the unaudited pro forma financial statements of Enduro Sponsor included elsewhere in this prospectus. The pro forma adjustments have been prepared as if the acquisition of the Acquired Properties and, with respect to the pro forma as adjusted information, the conveyance of the Net Profits Interest and the offer and sale of the trust units and application of the net proceeds therefrom, had taken place (i) on March 31, 2011, in the case of the pro forma balance sheet information as of


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March 31, 2011, and (ii) as of January 1, 2010, in the case of the pro forma statements of earnings for the three months ended March 31, 2011 and for the year ended December 31, 2010.
 
                                                                               
        Enduro
                             
    Enduro
  Sponsor
                             
    Sponsor
  Pro Forma
      Enduro
                     
    Pro Forma
  as Adjusted
      Sponsor
                     
    for the
  for the Offering
      Pro Forma
                     
    Acquisition
  (Including the
  Enduro
  as Adjusted
                     
    of the
  Conveyance of
  Sponsor
  for the Offering
                     
    Acquired
  Net Profits
  Pro Forma for the
  (including the
                     
    Properties   Interest)   Acquisition of the
  Conveyance of the
  Enduro Sponsor     Enduro Sponsor     Predecessor-DNR     Predecessor-EAC
    Three Months
  Three Months
  Acquired Properties   Net Profits Interest)   Three Months
  Inception
    Inception
    March 9, 2010
    January 1,
    Ended
  Ended
  Year Ended
  Year Ended
  Ended
  Through
    Through
    Through
    2010
    March 31,
  March 31,
  December 31,
  December 31,
  March 31,
  March 31,
    December 31,
    November 30,
    Through
    2011   2011   2010   2010   2011   2010     2010     2010     March 8, 2010
(In thousands)   (Unaudited)   (Unaudited)   (Unaudited)   (Unaudited)   (Unaudited)   (Unaudited)                  
Revenues
  $ 33,793     $ 31,672     $ 137,712     $ 127,421     $ 22,952     $       $ 3,975       $ 40,210       $ 12,164  
Net income (loss)
  $ (9,559 )   $ (6,601 )   $ (8,645 )   $ 2,917     $ (11,495 )   $ (77 )     $ (8,222 )     $ (19,515 )     $ (17,821 )
Total assets (at period end)
          $ 662,829                     $ 735,806     $ 100       $ 361,832       $ 397,314       $ 313,106  
Long-term liabilities, excluding current maturities (at period end)
          $ 77,392                     $ 260,392     $       $ 66,211       $ 587       $ 1,412  
Members’ equity/owners’ equity
          $ 555,166                     $ 445,143     $ 23       $ 273,939       $ 374,731       $ 290,073  
                                                                               
 
Summary Projected Cash Distributions
 
The following table presents a calculation of forecasted cash distributions to holders of trust units for the twelve months ending September 30, 2012, which was prepared by Enduro Sponsor based on the assumptions that are described below and in “Projected Cash Distributions— Significant Assumptions Used to Prepare the Projected Cash Distributions.”
 
Typically, cash payment is received by Enduro Sponsor for oil production 30 to 60 days after it is produced and for natural gas production 60 to 90 days after it is produced. Given that the trust is entitled to production effective May 1, 2011 and the initial distribution will not occur until October 2011, the initial distribution in October 2011 may relate to net profits received from production from May and June of 2011. The forecasted cash distributions assume that each of the other monthly distributions during the forecasted period will relate to production from a single month. To adjust for the lag between the timing of production and the timing of cash received by Enduro Sponsor and the trust, the forecasted cash distributions for the twelve months ending September 30, 2012 are based on estimated production of oil and natural gas for the twelve months ending April 30, 2012.
 
Unlike payments for production, payments related to hedges are settled during or very soon after the end of each month. As a result, and in an effort to better align payments associated with production and hedges, the trust will not bear any hedge settlement costs paid by Enduro Sponsor, or be entitled to any hedge payments received by Enduro Sponsor, for periods on or prior to June 30, 2011 (which is 60 days after May 1, 2011). In order to reflect this, the forecasted cash distributions for the twelve months ending September 30, 2012 reflect forecasted hedge settlements related to the twelve months ending June 30, 2012.
 
Enduro Sponsor does not as a matter of course make public projections as to future sales, earnings or other results. However, the management of Enduro Sponsor has prepared the projected financial information set forth below to present the projected cash distributions to the holders of the trust units based on the estimates and hypothetical assumptions described below. The accompanying projected financial information was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to projected financial information.


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In the view of Enduro Sponsor’s management, the accompanying unaudited projected financial information was prepared on a reasonable basis and reflects the best currently available estimates and judgments of Enduro Sponsor related to oil and natural gas production, operating expenses and development expenses, and other general and administrative expenses based on:
 
  •      the oil and natural gas production estimates for the twelve months ending April 30, 2012 contained in the reserve reports;
 
  •      estimated direct operating expenses and development expenses for the twelve months ending April 30, 2012 contained in the reserve reports;
 
  •      projected payments made or received pursuant to the hedge contracts for the twelve months ending June 30, 2012;
 
  •      estimated general and administrative expenses of $850,000 for the twelve months ending April 30, 2012; and
 
  •      an adjustment for the estimated production, revenue, operating expenses and development expenses (as adjusted to reflect that Enduro Sponsor has agreed to pay for $7.3 million of development expenses otherwise attributable to the trust) expected in the twelve months ending April 30, 2012 for drilling projects in the Haynesville Shale that are not included in the reserve reports.
 
The projected financial information was also based on the hypothetical assumption that prices for oil and natural gas remain constant at $100.00 per Bbl of oil and $4.50 per MMBtu of natural gas during the twelve months ending April 30, 2012. These hypothetical prices are then adjusted to take into account Enduro Sponsor’s estimate of the basis differential (based on location and quality of the production) between published prices and the prices actually received by Enduro Sponsor. Actual prices paid for oil and natural gas expected to be produced from the Underlying Properties during the twelve months ending April 30, 2012 will likely differ from these hypothetical prices due to fluctuations in the prices generally experienced with respect to the production of oil and natural gas and variations in basis differentials. For example, for the twelve months ending June 30, 2011, the published daily average closing WTI crude oil spot price per Bbl was approximately $89.40 and the daily average Henry Hub natural gas spot price per MMBtu was approximately $4.16.
 
Please read “Projected Cash Distributions — Significant Assumptions Used to Prepare the Projected Cash Distributions” and “Risk Factors — Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the trust and cash distributions to trust unitholders.”
 
Neither Enduro Sponsor’s independent auditors nor any other independent accountants have compiled, examined or performed any procedures with respect to the projected financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the projected financial information.
 
The projections and estimates and the hypothetical assumptions on which they are based are subject to significant uncertainties, many of which are beyond the control of Enduro Sponsor or the trust. Actual cash distributions to trust unitholders, therefore, could vary significantly based upon events or conditions occurring that are different from the events or conditions assumed to occur for purposes of these projections. Cash distributions to trust unitholders will be particularly sensitive to fluctuations in oil and natural gas prices. Please read “Risk Factors — Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the trust and cash distributions to trust unitholders.” As a result of typical production declines for oil and natural gas properties, production estimates generally decrease from year to year, and the projected cash distributions shown in the table below are not necessarily indicative of distributions for future years. Please read “Projected Cash Distributions — Sensitivity of Projected Cash Distributions to Oil and Natural Gas Production and Prices,” which shows projected effects on cash distributions from hypothetical changes in oil and natural gas production and prices. Because payments to


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the trust will be generated by depleting assets and the trust has a finite life with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent, in effect, a return of your original investment. Please read “Risk Factors — The reserves attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production. Therefore, proceeds to the trust and cash distributions to trust unitholders will decrease over time.”
 
         
    Projections for the Twelve
 
    Month Period Ending
 
Projected Cash Distributions to Trust Unitholders
  September 30, 2012  
    (In thousands,
 
    except per unit data)  
 
Underlying Properties sales volumes:
       
Oil (MBbl)(1)
    911  
Natural gas (MMcf)
    7,119  
         
Total sales (MBoe)
    2,097  
         
Assumed NYMEX price(2):
       
Oil (per Bbl)
  $ 100.00  
Natural gas (per MMBtu)
    4.50  
Assumed realized sales price(3):
       
Oil (per Bbl)
  $ 96.54  
Natural gas (per Mcf)
    4.63  
Calculation of net profits:
       
Gross profits(4):
       
Oil sales
  $ 87,940  
Natural gas sales
    32,979  
         
Total
    120,919  
         
Costs:
       
Direct operating expenses:
       
Lease operating expenses
  $ 23,489  
Production and other taxes
    9,225  
Development expenses(5)
    14,300  
         
Total
    47,014  
         
Settlement of hedge contracts(6)
    1,857  
         
Net adjustment for additional projects(7)
    (989 )
Net profits
    74,773  
         
Percentage allocable to Net Profits Interest
    80%  
         
         
Net profits to trust from Net Profits Interest
  $ 59,818  
         
Trust general and administrative expenses(8)
    850  
         
Cash available for distribution by the trust
  $ 58,968  
         
Cash distribution per trust unit (assumes 33,000,000 units)
  $ 1.79  
         
 
 
(1) Sales volumes for oil include 9 MBbls of NGLs.
 
(2) For a description of the effect of lower NYMEX prices on projected cash distributions, please read “Projected Cash Distributions — Sensitivity of Projected Cash Distributions to Oil and Natural Gas Production and Prices.”


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(3) Sales price net of forecasted gravity, quality, transportation, gathering and processing and marketing costs. For more information about the estimates and hypothetical assumptions made in preparing the table above, see “Projected Cash Distributions — Significant Assumptions Used to Prepare the Projected Cash Distributions.”
 
(4) Represents “gross profits” as described in “Computation of Net Profits.”
 
(5) Does not include development expenses related to 21 gross (2.4 net) wells associated with development drilling projects in the Haynesville Shale. Please read footnote 7.
 
(6) Reflects net cash impact of settlements of hedge contracts relating to production. See “The Underlying Properties — Hedge Contracts.”
 
(7) Net adjustment for additional projects reflects the expected drilling of 21 gross (2.4 net) wells in the Haynesville Shale during the forecast period associated with development drilling projects not reflected in the reserve reports but for which notifications have been received by Enduro Sponsor as of June 2011. These additional development drilling projects are expected to increase total sales volumes by 221 MBoe, total gross profits by $3.3 million and total lease operating and development expenses and production and other taxes by $4.3 million, which is expected to result in a decrease in net profits for the Underlying Properties by $989,000 and cash available for distribution to the trust by $791,000. The amount of estimated development expenses has been adjusted to reflect the agreement by Enduro Sponsor to pay for up to $9.1 million (or $7.3 million attributable to the trust’s Net Profits Interest) of the total estimated development expenses of $12.4 million related to the 21 gross (2.4 net) wells, thereby reducing the trust’s share of development expenses associated with these wells to $2.6 million. In the absence of this payment obligation by Enduro Sponsor, the cash available for distribution to the trust would be reduced by an additional $7.3 million during the forecast period. Please read “Projected Cash Distributions — Significant Assumptions Used to Prepare the Projected Cash Distributions — Net adjustment for additional projects.”
 
(8) Total general and administrative expenses of the trust on an annualized basis for the twelve months ending April 30, 2012 are expected to be $850,000 and will include the annual fees to the trustees, accounting fees, engineering fees, legal fees, printing costs and other expenses properly chargeable to the trust.
 
Recent Operational Performance
 
Production volume estimates from the Underlying Properties for the three months ended June 30, 2011 are 225 MBbls of oil and 1,865 MMcf of natural gas.
 
Enduro Sponsor
 
Enduro Sponsor is a privately-held Delaware limited liability company engaged in the production and development of oil and natural gas from properties located in Texas, Louisiana and New Mexico. Enduro Sponsor was formed on March 3, 2010.
 
As of December 31, 2010, Enduro Sponsor held interests in approximately 4,866 gross (919 net) producing wells, and had proved reserves of approximately 32.8 MMBoe.
 
After giving pro forma effect to the conveyance of the Net Profits Interest to the trust, the offering of the trust units contemplated by this prospectus and the application of the net proceeds as described in “Use of Proceeds,” as of March 31, 2011, Enduro Sponsor would have had total assets of $662.8 million and total liabilities of $107.7 million. For an explanation of the pro forma adjustments, please read “Financial Statements of Enduro Sponsor — Unaudited Pro Forma Financial Statements — Introduction.”
 
The address of Enduro Sponsor is 777 Main Street, Suite 800, Fort Worth, Texas 76102, and its telephone number is (817) 744-8200.


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The Offering
 
Trust units offered by Enduro Sponsor 13,200,000 trust units, or 15,180,000 trust units if the underwriters exercise their option to purchase additional trust units in full
 
Trust units owned by Enduro Sponsor after the offering 19,800,000 trust units, or 17,820,000 trust units if the underwriters exercise their option to purchase additional trust units in full
 
Trust units outstanding after the offering 33,000,000 trust units
 
Use of proceeds Enduro Sponsor is offering all of the trust units to be sold in this offering, including the trust units to be sold upon any exercise of the underwriters’ option to purchase additional trust units. The estimated net proceeds of this offering to be received by Enduro Sponsor will be approximately $      million, after deducting underwriting discounts and commissions, structuring fees and expenses, and $      million if the underwriters exercise their option to purchase additional trust units in full. Enduro Sponsor intends to use the net proceeds from this offering, including any proceeds from the exercise of the underwriters’ option to purchase additional trust units, to repay approximately $      million of the borrowings outstanding under its senior secured credit agreement and to make a distribution of approximately $      million to its sole member, Enduro Resource Holdings LLC (“Enduro Holdings”). The remaining $      million will be used to acquire additional oil and natural gas properties in the future for Enduro Sponsor (none of which have been identified). Enduro Sponsor is deemed to be an underwriter with respect to the trust units offered hereby. Please read “Use of Proceeds.” Affiliates of certain of the underwriters participating in this offering are lenders under Enduro Sponsor’s senior secured credit agreement and will receive a substantial portion of the proceeds from this offering pursuant to the repayment of a portion of the borrowings thereunder. Please read “Underwriting (Conflicts of Interest) — Conflicts of Interest/FINRA Rules.”
 
Proposed NYSE symbol “NDRO”
 
Monthly cash distributions The trust will pay monthly distributions to the holders of trust units as of the applicable record date (generally the 15th day of each calendar month) on or before the 10th business day after the record date. The first distribution from the trust to the trust unitholders will be made on or about October 28, 2011 to trust unitholders owning trust units on or about October 14, 2011.
 
Actual cash distributions to the trust unitholders will fluctuate monthly based upon the quantity of oil and natural gas produced from the Underlying Properties, the prices received


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for oil and natural gas production and other factors. Because payments to the trust will be generated by depleting assets with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent, in effect, a return of your original investment. Oil and natural gas production from proved reserves attributable to the Underlying Properties is expected to decline over time. Please read “Risk Factors.”
 
Dissolution of the trust The trust will dissolve upon the earliest to occur of the following: (1) the trust, upon approval of the holders of at least 75% of the outstanding trust units, sells the Net Profits Interest, (2) the annual cash available for distribution to the trust is less than $2 million for each of any two consecutive years, (3) the holders of at least 75% of the outstanding trust units vote in favor of dissolution or (4) the trust is judicially dissolved.
 
Estimated ratio of taxable income to distributions Enduro Sponsor estimates that a trust unitholder who owns the trust units purchased in this offering through the record date for distribution for the period ending December 31, 2013, will recognize, on a cumulative basis, an amount of federal taxable income for that period of approximately 30% of the cash distributed to such trust unitholder with respect to that period. Please read “Federal Income Tax Consequences — U.S. Federal Income Tax Consequences — Direct Taxation of Trust Unitholders” for the basis of this estimate.
 
Summary of income tax consequences Trust unitholders will be taxed directly on the income from assets of the trust. Enduro Sponsor and the trust intend to treat the Net Profits Interest, which will be granted to the trust on a perpetual basis, as a mineral royalty interest that generates ordinary income subject to depletion for U.S. federal income tax purposes. Please read “Federal Income Tax Consequences.”


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RISK FACTORS
 
Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the trust and cash distributions to trust unitholders.
 
The trust’s reserves and monthly cash distributions are highly dependent upon the prices realized from the sale of oil and natural gas. Prices of oil and natural gas can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the trust and Enduro Sponsor. These factors include, among others:
 
  •      regional, domestic and foreign supply and perceptions of supply of oil and natural gas;
 
  •      the level of demand and perceptions of demand for oil and natural gas;
 
  •      political conditions or hostilities in oil and natural gas producing countries;
 
  •      anticipated future prices of oil and natural gas and other commodities;
 
  •      weather conditions and seasonal trends;
 
  •      technological advances affecting energy consumption and energy supply;
 
  •      U.S. and worldwide economic conditions;
 
  •      the price and availability of alternative fuels;
 
  •      the proximity, capacity, cost and availability of gathering and transportation facilities;
 
  •      the volatility and uncertainty of regional pricing differentials;
 
  •      governmental regulations and taxation;
 
  •      energy conservation and environmental measures; and
 
  •      acts of force majeure.
 
Crude oil prices declined from record high levels in early July 2008 of over $140 per Bbl to below $45 per Bbl in February 2009 before rebounding to over $101 per Bbl in June 2011. Natural gas prices declined from over $13.57 per MMBtu in July 2008 to below $3.30 per MMBtu in October 2010 before rebounding to over $4.90 per MMBtu in June 2011.
 
Lower prices of oil and natural gas will reduce profits to which the trust is entitled and may ultimately reduce the amount of oil and natural gas that is economic to produce from the Underlying Properties. As a result, the operators of the Underlying Properties could determine during periods of low commodity prices to shut in or curtail production from wells on the Underlying Properties. In addition, the operators could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, an operator may abandon any well or property if it reasonably believes that the well or property can no longer produce oil or natural gas in commercially paying quantities. This could result in termination of the Net Profits Interest relating to the abandoned well or property.
 
The Underlying Properties are sensitive to decreasing commodity prices. The commodity price sensitivity is due to a variety of factors that vary from well to well, including the costs associated with water handling and disposal, chemicals, surface equipment maintenance, downhole casing repairs and reservoir pressure maintenance activities that are necessary to maintain production. As a result, the volatility of commodity prices may cause the expenses of certain wells to exceed the well’s revenue. If this scenario were to occur, the operator may decide to shut-in the well or plug and abandon the well. This scenario could reduce future cash distributions to trust unitholders.
 
Enduro Sponsor has entered into hedge contracts with respect to approximately 69%, 70% and 57% of expected production of oil and natural gas production for 2011, 2012 and 2013, respectively, from the total proved reserves attributable to the Underlying Properties in the reserve reports. The


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hedge contracts are intended to reduce exposure of the revenues from oil and natural gas production from the Underlying Properties to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. Some of the hedge contracts could limit the benefit to the trust of any increase in oil or natural gas prices through 2013. The trust will be required to bear its share of the hedge payments regardless of whether the corresponding quantities of oil and natural gas are produced or sold. Furthermore, Enduro Sponsor has not entered into any hedge contracts relating to oil and natural gas volumes expected to be produced after 2013, and the terms of the conveyance of the Net Profits Interest will prohibit Enduro Sponsor from entering into new hedging arrangements burdening the trust following the completion of this offering. As a result, the amount of the cash distributions will be subject to a greater fluctuation after 2013 due to changes in oil and natural gas prices. For a discussion of the hedge contracts, please read “The Underlying Properties — Hedge Contracts.”
 
Estimates of future cash distributions to trust unitholders are based on assumptions that are inherently subjective.
 
The projected cash distributions to trust unitholders for the twelve months ending September 30, 2012 contained elsewhere in this prospectus are based on Enduro Sponsor’s calculations, and Enduro Sponsor has not received an opinion or report on such calculations from any independent accountants or engineers. Such calculations are based on assumptions about drilling, production, crude oil and natural gas prices, hedging activities, development expenses, and other matters that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. In particular, these estimates have assumed that crude oil and natural gas production is sold in 2011 and 2012 based on assumed NYMEX prices of $100.00 per Bbl in the case of crude oil and $4.50 per MMBtu in the case of natural gas. However, actual sales prices may be significantly lower. Additionally, these estimates assume the Underlying Properties will achieve production volumes set forth in the reserve reports; however, actual production volumes may be significantly lower. If prices or production are lower than expected, the amount of cash available for distribution to trust unitholders would be reduced. Furthermore, there have been an additional 21 gross (2.4 net) wells spud or proposed and approved by Enduro Sponsor in 2011 that are not represented in the reserve report because they would not be classified as proved locations but would rather be classified as probable locations based on the information available on December 31, 2010. Although Enduro Sponsor has agreed to pay up to $9.1 million of the development expenses associated with these wells incurred after May 1, 2011, Enduro Sponsor will not pay any amounts in excess of $9.1 million ($7.3 million attributable to the trust’s Net Profits Interest), even if future capital expenditures increase substantially. Thus, any additional drilling opportunities not reflected in the reserve reports could increase development expenses significantly without an immediate increase in production or revenues, which could decrease the amount of cash available for distribution to trust unitholders unless and until production and revenue from the new wells resulted in the recoupment of such expenses.
 
Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the trust and the value of the trust units.
 
The value of the trust units and the amount of future cash distributions to the trust unitholders will depend upon, among other things, the accuracy of the reserves and future production estimated to be attributable to the trust’s interest in the Underlying Properties. Please read “The Underlying Properties — Reserve Reports” for a discussion of the method of allocating proved reserves to the Underlying Properties and the Net Profits Interest. It is not possible to measure underground accumulations of oil and natural gas in an exact way, and estimating reserves is inherently uncertain. Ultimately, actual production and revenues for the Underlying Properties could vary both positively and negatively and in material amounts from estimates. Furthermore, direct operating expenses and development expenses relating to the Underlying Properties could be substantially higher than current


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estimates. Petroleum engineers are required to make subjective estimates of underground accumulations of oil and natural gas based on factors and assumptions that include:
 
  •      historical production from the area compared with production rates from other producing areas;
 
  •      oil and natural gas prices, production levels, Btu content, production expenses, transportation costs, severance and excise taxes and development expenses; and
 
  •      the assumed effect of expected governmental regulation and future tax rates.
 
Changes in these assumptions and amounts of actual direct operating expenses and development expenses could materially decrease reserve estimates. In addition, the quantities of recovered reserves attributable to the Underlying Properties may decrease in the future as a result of future decreases in the price of oil or natural gas.
 
The Third Party Operators are the operators of approximately 99.3% of the wells on the Underlying Properties and, therefore, Enduro Sponsor is not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.
 
As of December 31, 2010, approximately 99.3% of the wells on the Underlying Properties were operated by the Third Party Operators. As a result, Enduro Sponsor has limited ability to exercise influence over, and control the risks or costs associated with, the operations of these properties. The failure of a Third Party Operator to adequately or efficiently perform operations, a Third Party Operator’s breach of the applicable operating agreements or a Third Party Operator’s failure to act in ways that are in Enduro Sponsor’s or the trust’s best interests could reduce production and revenues. Further, none of the Third Party Operators of the Underlying Properties are obligated to undertake any development activities, so any development and production activities will be subject to their reasonable discretion. The success and timing of drilling and development activities on properties operated by the Third Party Operators, therefore, depends on a number of factors that will be largely outside of Enduro Sponsor’s control, including:
 
  •      the timing and amount of capital expenditures, which could be significantly more than anticipated;
 
  •      the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
 
  •      the Third Party Operator’s expertise, operating efficiency and financial resources;
 
  •      approval of other participants in drilling wells;
 
  •      the selection of technology;
 
  •      the selection of counterparties for the sale of production; and
 
  •      the rate of production of the reserves.
 
The Third Party Operators may elect not to undertake development activities, or may undertake such activities in an unanticipated fashion, which may result in significant fluctuations in capital expenditures and amounts available for distribution to trust unitholders.
 
Developing oil and natural gas wells and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect future production from the Underlying Properties. Any delays, reductions or cancellations in development and producing activities could decrease revenues that are available for distribution to trust unitholders.
 
The process of developing oil and natural gas wells and producing oil and natural gas on the Underlying Properties is subject to numerous risks beyond the trust’s, Enduro Sponsor’s and the Third Party Operators’ control, including risks that could delay the operators’ current drilling or production


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schedule and the risk that drilling will not result in commercially viable oil or natural gas production. The ability of the operators to carry out operations or to finance planned development expenses could be materially and adversely affected by any factor that may curtail, delay, reduce or cancel development and production, including:
 
  •      delays imposed by or resulting from compliance with regulatory requirements, including permitting;
 
  •      unusual or unexpected geological formations;
 
  •      shortages of or delays in obtaining equipment and qualified personnel;
 
  •      lack of available gathering facilities or delays in construction of gathering facilities;
 
  •      lack of available capacity on interconnecting transmission pipelines;
 
  •      equipment malfunctions, failures or accidents;
 
  •      unexpected operational events and drilling conditions;
 
  •      reductions in oil or natural gas prices;
 
  •      market limitations for oil or natural gas;
 
  •      pipe or cement failures;
 
  •      casing collapses;
 
  •      lost or damaged drilling and service tools;
 
  •      loss of drilling fluid circulation;
 
  •      uncontrollable flows of oil and natural gas, insert gas, water or drilling fluids;
 
  •      fires and natural disasters;
 
  •      environmental hazards, such as oil and natural gas leaks, pipeline ruptures and discharges of toxic gases;
 
  •      adverse weather conditions; and
 
  •      oil or natural gas property title problems.
 
In the event that planned operations, including drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, estimated future distributions to trust unitholders may be reduced. In the event an operator incurs increased costs due to one or more of the above factors or for any other reason and is not able to recover such costs from insurance, the estimated future distributions to trust unitholders may be reduced.
 
The trust is passive in nature and neither the trust nor the trust unitholders will have any ability to influence Enduro Sponsor or control the operations or development of the Underlying Properties.
 
The trust units are a passive investment that entitle the trust unitholder to only receive cash distributions from the Net Profits Interest and hedge contracts being conveyed to the trust. Trust unitholders have no voting rights with respect to Enduro Sponsor and, therefore, will have no managerial, contractual or other ability to influence Enduro Sponsor’s or the Third Party Operators’ activities or the operations of the Underlying Properties. Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners of oil and natural gas properties. The Third Party Operators operate approximately 99.3% of the wells on the Underlying Properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making all decisions relating to drilling


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activities, sale of production, compliance with regulatory requirements and other matters that affect the property.
 
Shortages of equipment, services and qualified personnel could increase costs of developing and operating the Underlying Properties and result in a reduction in the amount of cash available for distribution to the trust unitholders.
 
The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could hinder the ability of the operators of the Underlying Properties to conduct the operations which they currently have planned for the Underlying Properties, which would reduce the amount of cash received by the trust and available for distribution to the trust unitholders.
 
The trust units may lose value as a result of title deficiencies with respect to the Underlying Properties.
 
Enduro Sponsor acquired the Underlying Properties through various acquisitions since December 2010. The existence of a material title deficiency with respect to the Underlying Properties could reduce the value of a property or render it worthless, thus adversely affecting the Net Profits Interest and the distributions to trust unitholders. Enduro Sponsor does not obtain title insurance covering mineral leaseholds, and Enduro Sponsor’s failure to cure any title defects may cause Enduro Sponsor to lose its rights to production from the Underlying Properties. In the event of any such material title problem, profits available for distribution to trust unitholders and the value of the trust units may be reduced.
 
Enduro Sponsor may transfer all or a portion of the Underlying Properties at any time without trust unitholder consent, subject to specified limitations.
 
Enduro Sponsor may at any time transfer all or part of the Underlying Properties, subject to and burdened by the Net Profits Interest, and may, along with the Third Party Operators, abandon individual wells or properties reasonably believed to be uneconomic. Trust unitholders will not be entitled to vote on any transfer or abandonment of the Underlying Properties, and the trust will not receive any profits from any such transfer, except in the limited circumstances when the Net Profits Interest is released in connection with such transfer, in which case the trust will receive an amount equal to the fair market value (net of sales costs) of the Net Profits Interest released. Please read “The Underlying Properties — Sale and Abandonment of Underlying Properties.” Following any sale or transfer of any of the Underlying Properties, if the Net Profits Interest is not released in connection with such sale or transfer, the Net Profits Interest will continue to burden the transferred property and net profits attributable to such property will be calculated as part of the computation of net profits described in this prospectus. Enduro Sponsor may delegate to the transferee responsibility for all of Enduro Sponsor’s obligations relating to the Net Profits Interest on the portion of the Underlying Properties transferred.
 
In addition, Enduro Sponsor may, without the consent of the trust unitholders, require the trust to release the Net Profits Interest associated with any lease that accounts for less than or equal to 0.25% of the total production from the Underlying Properties in the prior 12 months and provided that the Net Profits Interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the trust of $500,000. These releases will be made only in connection with a sale by Enduro Sponsor of the relevant Underlying Properties and are conditioned upon an


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amount equal to the fair market value of such Net Profits Interest being treated as an offset amount against costs and expenses. Enduro Sponsor has not identified for sale any of the Underlying Properties.
 
The Third Party Operators and Enduro Sponsor may enter into farm-out, operating, participation and other similar agreements to develop the property without the consent or approval of the trustee or any trust unitholder.
 
The reserves attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production. Therefore, proceeds to the trust and cash distributions to trust unitholders will decrease over time.
 
The profits payable to the trust attributable to the Net Profits Interest are derived from the sale of production of oil and natural gas from the Underlying Properties. The reserves attributable to the Underlying Properties are depleting assets, which means that the reserves and the quantity of oil and natural gas produced from the Underlying Properties will decline over time. Based on the estimated production and operating expenses in the reserve report of the Underlying Properties, the oil and natural gas production from proved reserves attributable to the Underlying Properties is projected to be shallow declining over the next five years. Actual decline rates may vary from this projected decline rate. In the event expected future development is delayed, reduced or cancelled, the average rate of decline will likely exceed 9% per year.
 
Future maintenance projects on the Underlying Properties may affect the quantity of proved reserves that can be economically produced from wells on the Underlying Properties. The timing and size of these projects will depend on, among other factors, the market prices of oil and natural gas. Neither Enduro Sponsor nor, to Enduro Sponsor’s knowledge, the Third Party Operators have a contractual obligation to develop or otherwise pay development expenses on the Underlying Properties in the future. Enduro Sponsor, however, will have an obligation to pay up to $9.1 million of development expenses (or $7.3 million attributable to the trust’s 80% indirect interest in the Underlying Properties) for projects in the Haynesville Shale for which notifications have been received by Enduro Sponsor as of June 2011, and which are a part of Enduro Sponsor’s $37 million 2011 capital budget for the Underlying Properties. Furthermore, with respect to properties for which Enduro Sponsor is not designated as the operator, Enduro Sponsor has limited control over the timing or amount of those development expenses. Enduro Sponsor also has the right to non-consent and not participate in the development expenses on properties for which it is not the operator, in which case Enduro Sponsor and the trust will not receive the production resulting from such development expenses. If the operators of the Underlying Properties do not implement maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by Enduro Sponsor or estimated in the reserve report.
 
The trust agreement will provide that the trust’s activities will be limited to owning the Net Profits Interest and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyance related to the Net Profits Interest. As a result, the trust will not be permitted to acquire other oil and natural gas properties or net profits interests to replace the depleting assets and production attributable to the Net Profits Interest.
 
Because the net profits payable to the trust are derived from the sale of depleting assets, the portion of the distributions to trust unitholders attributable to depletion may be considered to have the effect of a return of capital as opposed to a return on investment. Eventually, the Underlying Properties burdened by the Net Profits Interest may cease to produce in commercially paying quantities and the trust may, therefore, cease to receive any distributions of net profits therefrom.


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An increase in the differential between the price realized by Enduro Sponsor for oil or natural gas produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the profits to the trust and, therefore, the cash distributions by the trust and the value of trust units.
 
The prices received for Enduro Sponsor’s oil and natural gas production usually fall below the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the price received and the benchmark price is called a basis differential. The differential may vary significantly due to market conditions, the quality and location of production and other factors. Enduro Sponsor cannot accurately predict oil or natural gas differentials. Increases in the differential between the realized price of oil and natural gas and the benchmark price for oil and natural gas could reduce the profits to the trust, the cash distributions by the trust and the value of the trust units.
 
The amount of cash available for distribution by the trust will be reduced by the amount of any costs and expenses related to the Underlying Properties and other costs and expenses incurred by the trust.
 
The trust will indirectly bear an 80% share of all costs and expenses related to the Underlying Properties, such as direct operating expenses, development expenses and hedge expenses, which will reduce the amount of cash received by the trust and thereafter distributable to trust unitholders. Accordingly, higher costs and expenses related to the Underlying Properties will directly decrease the amount of cash received by the trust in respect of its Net Profits Interest. Please read “The Underlying Properties — Unaudited Pro Forma Combined Financial and Operating Data of the Underlying Properties.” Historical costs may not be indicative of future costs. For example, the Third Party Operators may in the future propose additional drilling projects that significantly increase the capital expenditures associated with the Underlying Properties, which could reduce cash available for distribution by the trust. In addition, cash available for distribution by the trust will be further reduced by the trust’s general and administrative expenses, which are expected to be approximately $850,000 for the twelve months ending April 30, 2012. For details about these general and administrative expenses, please read “Description of the Trust Agreement — Fees and Expenses.”
 
If direct operating expenses, development expenses and hedge expenses on the Underlying Properties together with the other costs exceed gross profits of production from the Underlying Properties, the trust will not receive net profits from those properties until future gross profits from production exceed the total of the excess costs, plus accrued interest at the prime rate. If the trust does not receive net profits pursuant to the Net Profits Interest, or if such net profits are reduced, the trust will not be able to distribute cash to the trust unitholders, or such cash distributions will be reduced, respectively. Development activities may not generate sufficient additional revenue to repay the costs.
 
The generation of profits for distribution by the trust depends in part on access to and operation of gathering, transportation and processing facilities. Any limitation in the availability of those facilities could interfere with sales of oil and natural gas production from the Underlying Properties.
 
The amount of oil and natural gas that may be produced and sold from a well is subject to curtailment in certain circumstances, such as by reason of weather conditions, pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered oil and natural gas to meet quality specifications of gathering lines or downstream transporters, excessive line pressure which prevents delivery, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments may vary from a few days to several months. In many cases, the operators of the Underlying Properties are provided limited notice, if any, as to when production will be curtailed and the duration of such curtailments. If the operators of the Underlying Properties are forced to reduce production due to such a curtailment, the revenues of the trust and the


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amount of cash distributions to the trust unitholders would similarly be reduced due to the reduction of profits from the sale of production.
 
The trustee must, under certain circumstances, sell the Net Profits Interest and dissolve the trust prior to the expected termination of the trust. As a result, trust unitholders may not recover their investment.
 
The trustee must sell the Net Profits Interest and dissolve the trust if the holders of at least 75% of the outstanding trust units approve the sale or vote to dissolve the trust. The trustee must also sell the Net Profits Interest and dissolve the trust if the annual gross profits from the Underlying Properties attributable to the Net Profits Interest are less than $2 million for each of any two consecutive years. The net profits of any such sale will be distributed to the trust unitholders.
 
Enduro Sponsor may sell trust units in the public or private markets, and such sales could have an adverse impact on the trading price of the trust units.
 
After the closing of the offering, Enduro Sponsor will hold an aggregate of 19,800,000 trust units, assuming no exercise of the underwriters’ option to purchase additional trust units. Enduro Sponsor has agreed not to sell any trust units for a period of 180 days after the date of this prospectus without the consent of Barclays Capital Inc. Please read “Underwriting (Conflicts of Interest).” After such period, Enduro Sponsor may sell trust units in the public or private markets, and any such sales could have an adverse impact on the price of the trust units or on any trading market that may develop. The trust has granted registration rights to Enduro Sponsor, which, if exercised, would facilitate sales of trust units by Enduro Sponsor.
 
There has been no public market for the trust units.
 
The initial public offering price of the trust units will be determined by negotiation among Enduro Sponsor and the underwriters. Among the factors to be considered in determining the number of trust units to be offered hereby and the initial public offering price will be estimates of distributions to trust unitholders; overall quality of the oil and natural gas properties attributable to the Underlying Properties; the history and prospects for the energy industry; Enduro Sponsor’s financial information; the prevailing securities markets at the time of this offering and the recent market prices of, and the demand for, publicly traded units of royalty trusts. None of Enduro Sponsor, the trust or the underwriters will obtain any independent appraisal or other opinion of the value of the Net Profits Interest, other than the reserve report prepared by Cawley Gillespie.
 
The trading price for the trust units may not reflect the value of the Net Profits Interest held by the trust.
 
The trading price for publicly traded securities similar to the trust units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution by the trust will vary in response to numerous factors outside the control of the trust, including prevailing prices for sales of oil and natural gas production from the Underlying Properties and the timing and amount of direct operating expenses and development expenses. Consequently, the market price for the trust units may not necessarily be indicative of the value that the trust would realize if it sold the Net Profits Interest to a third-party buyer. In addition, such market price may not necessarily reflect the fact that since the assets of the trust are depleting assets, a portion of each cash distribution paid with respect to the trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. As a result, distributions made to a trust unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the trust unitholder.


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Conflicts of interest could arise between Enduro Sponsor and its affiliates, on the one hand, and the trust and the trust unitholders, on the other hand.
 
As working interest owners in, and the operators of certain wells on, the Underlying Properties, Enduro Sponsor and its affiliates could have interests that conflict with the interests of the trust and the trust unitholders. For example:
 
  •      Enduro Sponsor’s interests may conflict with those of the trust and the trust unitholders in situations involving the development, maintenance, operation or abandonment of certain wells on the Underlying Properties for which Enduro Sponsor acts as the operator. Enduro Sponsor may also make decisions with respect to development expenses that adversely affect the Underlying Properties. These decisions include reducing development expenses on properties for which Enduro Sponsor acts as the operator, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the trust in the future.
 
  •      Enduro Sponsor may sell some or all of the Underlying Properties without taking into consideration the interests of the trust unitholders. Such sales may not be in the best interests of the trust unitholders. These purchasers may lack Enduro Sponsor’s experience or its credit worthiness. Enduro Sponsor also has the right, under certain circumstances, to cause the trust to release all or a portion of the Net Profits Interest in connection with a sale of a portion of the Underlying Properties to which such Net Profits Interest relates. In such an event, the trust is entitled to receive the fair value (net of sales costs) of the Net Profits Interest released. Please read “The Underlying Properties — Sale and Abandonment of Underlying Properties.”
 
  •      Enduro Sponsor has registration rights and can sell its trust units without considering the effects such sale may have on trust unit prices or on the trust itself. Additionally, Enduro Sponsor can vote its trust units in its sole discretion without considering the interests of the other trust unitholders. Enduro Sponsor is not a fiduciary with respect to the trust unitholders or the trust and will not owe any fiduciary duties or liabilities to the trust unitholders or the trust.
 
The trust is managed by a trustee who cannot be replaced except by a majority vote of the trust unitholders at a special meeting, which may make it difficult for trust unitholders to remove or replace the trustee.
 
The affairs of the trust will be managed by the trustee. Your voting rights as a trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for an annual or other periodic re-election of the trustee. The trust agreement provides that the trustee may only be removed and replaced by the holders of a majority of the trust units present in person or by proxy at a meeting of such holders where a quorum is present, including trust units held by Enduro Sponsor, called by either the trustee or the holders of not less than 10% of the outstanding trust units. As a result, it will be difficult for public trust unitholders to remove or replace the trustee without the cooperation of Enduro Sponsor so long as it holds a significant percentage of total trust units.
 
Trust unitholders have limited ability to enforce provisions of the Net Profits Interest, and Enduro Sponsor’s liability to the trust is limited.
 
The trust agreement permits the trustee to sue Enduro Sponsor or any other future owner of the Underlying Properties to enforce the terms of the conveyance creating the Net Profits Interest. If the trustee does not take appropriate action to enforce provisions of the conveyance, trust unitholders’ recourse would be limited to bringing a lawsuit against the trustee to compel the trustee to take specified actions. The trust agreement expressly limits a trust unitholder’s ability to directly sue Enduro Sponsor or any other third party other than the trustee. As a result, trust unitholders will not be able to


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sue Enduro Sponsor or any future owner of the Underlying Properties to enforce these rights. Furthermore, the Net Profits Interest conveyance provides that, except as set forth in the conveyance, Enduro Sponsor will not be liable to the trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts without gross negligence or willful misconduct.
 
Courts outside of Delaware may not recognize the limited liability of the trust unitholders provided under Delaware law.
 
Under the Delaware Statutory Trust Act, trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.
 
The operations of the Underlying Properties are subject to environmental laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or result in significant costs and liabilities, which could reduce the amount of cash available for distribution to trust unitholders.
 
The oil and natural gas exploration and production operations on the Underlying Properties are subject to stringent and comprehensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that apply to the operations on the Underlying Properties, including the requirement to obtain a permit before conducting drilling, waste disposal or other regulated activities; the restriction of types, quantities and concentrations of materials that can be released into the environment; the incurrence of significant development expenses to install pollution or safety-related controls at the operated facilities; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often times requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of the operations on the Underlying Properties. Furthermore, the inability to comply with environmental laws and regulations in a cost-effective manner, such as removal and disposal of produced water and other generated oil and gas wastes, could impair the operators’ ability to produce oil and natural gas commercially from the Underlying Properties, which would reduce profits attributable to the Net Profits Interest.
 
There is inherent risk of incurring significant environmental costs and liabilities in the operations on the Underlying Properties as a result of the handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related to operations, and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, the operators could be subject to joint and several strict liability for the removal or remediation of previously released materials or property contamination regardless of whether such operators were responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which wells are drilled and facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose the operators of the Underlying Properties to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition and results of operations and could reduce the amount of cash available for distribution to trust unitholders. Changes in environmental laws and regulations


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occur frequently, and any changes that result in more stringent or costly operational control requirements or waste handling, storage, transport, disposal or cleanup requirements could require the operators of the Underlying Properties to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition.
 
The trust will indirectly bear 80% of all costs and expenses paid by Enduro Sponsor, including those related to environmental compliance and liabilities associated with the Underlying Properties, including costs and liabilities resulting from conditions that existed prior to Enduro Sponsor’s acquisition of the Underlying Properties unless such costs and expenses result from the operator’s negligence or misconduct. In addition, as a result of the increased cost of compliance, the operators of the Underlying Properties may decide to discontinue drilling.
 
Neither Enduro Sponsor nor the trust is generally entitled to, nor required to provide, indemnity to third party operators with respect to pollution liability and associated environmental remediation costs. However, Enduro Sponsor may be required to provide, and may be entitled to, indemnity from third party operators with respect to such liabilities and costs in the event of the other party’s gross negligence or misconduct. In addition, Enduro Sponsor has agreed to assume certain environmental liabilities of prior owners of the Underlying Properties in connection with the purchase thereof.
 
The amount of cash available for distribution by the trust could be reduced by expenses caused by uninsured claims.
 
Enduro Sponsor maintains insurance coverage against potential losses that it believes are customary in its industry. Enduro Sponsor currently maintains general liability insurance and excess liability coverage with limits of $1 million and $20 million per occurrence, respectively, and $2 million and $20 million in the aggregate, respectively. Enduro Sponsor’s excess liability coverage has a deductible of $10,000 per occurrence, while there is no deductible on the general liability insurance. The general liability insurance covers Enduro Sponsor and its subsidiaries for legal and contractual liabilities arising out of bodily injury or property damage, including any resulting loss of use to third parties, and for sudden and accidental pollution or environmental liability, while the excess liability coverage is in addition to and triggered if the general liability per occurrence limit is reached. In addition, Enduro Sponsor maintains control of well insurance with per occurrence limits ranging from $5 million to $20 million and deductibles ranging from $100,000 to $200,000 depending on the status of the well. Enduro Sponsor’s general liability insurance and excess liability policies do not provide coverage with respect to legal and contractual liabilities of the trust.
 
Enduro Sponsor does not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, Enduro Sponsor believes its general liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations in accordance with, and subject to, the terms of such policies. These policies may not cover fines, penalties or costs and expenses related to government-mandated clean up of pollution. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise or that Enduro Sponsor will be able to maintain adequate insurance at rates it considers reasonable. The occurrence of an event not fully covered by insurance could result in a significant decrease in the amount of cash available for distribution by the trust.
 
The operations of the Underlying Properties are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or expose the operator to significant liabilities, which could reduce the amount of cash available for distribution to trust unitholders.
 
The production and development operations on the Underlying Properties are subject to complex and stringent laws and regulations. In order to conduct their operations in compliance with


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these laws and regulations, the operators of the Underlying Properties must obtain and maintain numerous permits, drilling bonds, approvals and certificates from various federal, state and local governmental authorities and engage in extensive reporting. The operators of the Underlying Properties may incur substantial costs and experience delays in order to maintain compliance with these existing laws and regulations, and the trust will bear an 80% share of these costs. In addition, the operators’ costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to their operations. Such costs could have a material adverse effect on the operators’ business, financial condition and results of operations and reduce the amount of cash received by the trust in respect of the Net Profits Interest. The operators of the Underlying Properties must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of the Underlying Properties are shippers on interstate pipelines, they must comply with the tariffs of such pipelines and with federal policies related to the use of interstate capacity, and such compliance costs will be borne in part by the trust.
 
Laws and regulations governing exploration and production may also affect production levels. The operators of the Underlying Properties are required to comply with federal and state laws and regulations governing conservation matters, including: provisions related to the unitization or pooling of the oil and natural gas properties; the establishment of maximum rates of production from wells; the spacing of wells; the plugging and abandonment of wells; and the removal of related production equipment. Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increase capital costs on the part of the operators and third party downstream natural gas transporters. These and other laws and regulations can limit the amount of oil and natural gas the operators can produce from their wells, limit the number of wells they can drill, or limit the locations at which they can conduct drilling operations, which in turn could negatively impact trust distributions, estimated and actual future net revenues to the trust and estimates of reserves attributable to the trust’s interests.
 
New laws or regulations, or changes to existing laws or regulations, may unfavorably impact the operators of the Underlying Properties, could result in increased operating costs or have a material adverse effect on their financial condition and results of operations and reduce the amount of cash received by the trust. For example, Congress is currently considering legislation that, if adopted in its proposed form, would subject companies involved in oil and natural gas exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, the elimination of certain U.S. federal tax incentives and deductions available to oil and natural gas exploration and production activities and the prohibition or additional regulation of private energy commodity derivative and hedging activities. These and other potential regulations could increase the operating costs of the Underlying Properties, reduce the operators’ liquidity, delay the operators’ operations or otherwise alter the way the operators conduct their business, any of which could have a material adverse effect on the trust and the amount of cash available for distribution to trust unitholders.
 
Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that the operators produce while the physical effects of climate change could disrupt their production and cause them to incur significant costs in preparing for or responding to those effects.
 
The oil and gas industry is a direct source of certain greenhouse gas (“GHG”) emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact future operations on the Underlying Properties. On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the Earth’s atmosphere and other climate changes. Based on these findings, the agency has begun adopting and implementing regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. During 2010, the EPA adopted two sets of rules


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regulating GHG emissions under the Clean Air Act, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The stationary source rule “tailors” these permitting programs to apply to certain stationary sources in a multi-step process, with the largest sources first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that will be established by the states or, in some instances, by the EPA on a case-by-case basis. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. These EPA rulemakings could affect the operations on the Underlying Properties or the ability of the operators of the Underlying Properties to obtain air permits for new or modified facilities. In addition, on November 30, 2010, the EPA published final regulations expanding the existing greenhouse gas monitoring and reporting rule to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage and distribution facilities. Reporting of GHG emissions from such facilities will be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. The Underlying Properties may be subject to these requirements or become subject to them in the future.
 
In addition, the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, and almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from the equipment or operations of the operators of the Underlying Properties could require the operators to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with their operations. Such requirements could also adversely affect demand for the oil and natural gas produced, all of which could reduce profits attributable to the Net Profits Interest and, as a result, the trust’s cash available for distribution.
 
Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact the operators of the Underlying Properties and the trust. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, Enduro Sponsor cannot predict the financial impact of related developments on the operators of the Underlying Properties or the trust.
 
Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the operators’ assets and operations and, consequently, may reduce profits attributable to the Net Profits Interest and, as a result, the trust’s cash available for distribution.
 
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect the services of the operators of the Underlying Properties.
 
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the


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EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel fuel under the Safe Drinking Water Act’s Underground Injection Control Program and has commenced drafting guidance for permitting authorities and the industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel fuel. Industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012. Other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy (“DOE”), the U.S. Government Accountability Office and the White House Council for Environmental Quality. The U.S. Department of the Interior is also considering regulation of hydraulic fracturing activities on public lands. In addition, legislation called the Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. For example, on June 17, 2011, Texas signed into law a bill that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production) and the public. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is regulated at the federal level, Enduro Sponsor’s and the Third Party Operators’ fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Further, at least three local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities, while some state and local governments in the Marcellus Shale region in Pennsylvania and New York have considered or imposed temporary moratoria on drilling operations using hydraulic fracturing until further study of the potential environmental and human health impacts by the EPA or the relevant agencies are completed. No assurance can be given as to whether or not similar measures might be considered or implemented in the jurisdictions in which the Underlying Properties are located. If new laws or regulations that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in Texas, Louisiana or New Mexico, such legal requirements could make it more difficult or costly for Enduro Sponsor or the Third Party Operators to perform hydraulic fracturing activities and thereby could affect the determination of whether a well is commercially viable. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that the operators are ultimately able to produce in commercially paying quantities from the Underlying Properties.
 
The bankruptcy of Enduro Sponsor or any of the Third Party Operators could impede the operation of the wells and the development of the proved undeveloped reserves.
 
The value of the Net Profits Interest and the trust’s ultimate cash available for distribution will be highly dependent on the financial condition of the operators of the Underlying Properties. None of the operators of the Underlying Properties, including Enduro Sponsor, has agreed with the trust to maintain a certain net worth or to be restricted by other similar covenants, and Enduro Sponsor intends to use a portion of the net proceeds of this offering for general limited liability company purposes instead of retaining all or a portion to pay costs for the operation and development of the Underlying Properties.
 
The ability to develop and operate the Underlying Properties depends on the future financial condition and economic performance and access to capital of the operators of those properties, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of Enduro


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Sponsor and the Third Party Operators. Please read “Information about Enduro Resource Partners LLC (Enduro Sponsor)” for additional information relating to Enduro Sponsor, including information relating to the business of Enduro Sponsor, historical financial statements of Enduro Sponsor and other financial information relating to Enduro Sponsor. This prospectus contains no financial information about the Third Party Operators. Enduro Sponsor will not be a reporting company following this offering and will not be required to file periodic reports with the SEC pursuant to the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Therefore, as a trust unitholder, you will not have access to financial information about Enduro Sponsor.
 
In the event of the bankruptcy of an operator of the Underlying Properties, the working interest owners in the affected properties will have to seek a new party to perform the development and the operations of the affected wells. The working interest owners may not be able to find a replacement driller or operator, and they may not be able to enter into a new agreement with such replacement party on favorable terms within a reasonable period of time. As a result, such a bankruptcy may result in reduced production from the reserves and decreased distributions to trust unitholders.
 
In the event of the bankruptcy of Enduro Sponsor, if a court held that the Net Profits Interest was part of the bankruptcy estate, the trust may be treated as an unsecured creditor with respect to the Net Profits Interest attributable to properties in Louisiana and New Mexico.
 
It is well-established under Texas law that the conveyance of a net profits interest constitutes the conveyance of a presently vested, non-possessory interest in real property. Therefore, Enduro Sponsor and the trust believe that, in a bankruptcy of Enduro Sponsor, the Net Profits Interest would be viewed as a separate property interest under Texas law and, as such, outside of Enduro Sponsor’s bankruptcy estate. Likewise, Enduro Sponsor and the trust believe that the Net Profits Interest would be viewed as a separate property interest under the laws of Louisiana and outside of Enduro Sponsor’s bankruptcy estate. Since enactment of the Louisiana Mineral Code in 1975, Louisiana courts have classified an overriding royalty interest as a real right and an incorporeal immovable (similar to a real property interest). Although there are no reported Louisiana court cases addressing whether a net profits interest, carved out of the interest of a mineral lessee under an oil and gas lease, should be similarly classified as a real right and an incorporeal immovable, a 1972 Colorado federal court applying Louisiana law did conclude that such a net profits interest was comparable to an overriding royalty interest and, thus, was properly so classified. Similarly, Enduro Sponsor and the trust believe that a New Mexico court would rule that the conveyance of a net profits interest constitutes a conveyance of a real property interest. While no New Mexico case has clearly defined the nature of a “net profits interest” independent of the creating instrument, New Mexico case law has held that an overriding royalty interest in a mineral lease is a real property interest under New Mexico law. The 10th Circuit Court of Appeals has held that a net profits interest is “similar to” an overriding royalty interest. Given that the conveyance of the Net Profits Interest will contain a provision stating that it is the express intent of the parties that the conveyance of the Net Profits Interest constitutes a conveyance of a royalty interest in real property, in the event of a bankruptcy on the part of Enduro Sponsor, under New Mexico law, the Net Profits Interest would likely not be treated as part of Enduro Sponsor’s bankruptcy estate. Further, it is relevant that Enduro Sponsor and the trust have structured the Net Profits Interest as an overriding royalty interest in gross production payable on the basis of net profits. Nevertheless, the outcome is not certain given that there are not any dispositive Louisiana or New Mexico Supreme Court cases directly concluding that a conveyance of a net profits interest: (i) in the case of Louisiana, constitutes the conveyance of a real right and an incorporeal immovable (similar to a real property interest) or (ii) in the case of New Mexico, constitutes the conveyance of a real property interest. As such, in a bankruptcy of Enduro Sponsor, to the extent Louisiana or New Mexico law were held to be applicable, the Net Profits Interest might be considered an asset of the bankruptcy estate and used to satisfy obligations to creditors of Enduro Sponsor, in which case the trust would be an unsecured creditor of Enduro Sponsor at risk of losing the entire value of the Net Profits Interest to senior creditors.


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Adverse developments in Texas, Louisiana or New Mexico could adversely impact the results of operations and cash flows of the Underlying Properties and reduce the amount of cash available for distributions to trust unitholders.
 
The operations of the Underlying Properties are focused on the production and development of oil and natural gas within the states of Texas, Louisiana and New Mexico. As a result, the results of operations and cash flows of the Underlying Properties depend upon continuing operations in these areas. This concentration could disproportionately expose the trust’s interests to operational and regulatory risk in these areas. Due to the lack of diversification in geographic location, adverse developments in exploration and production of oil and natural gas in any of these areas of operation could have a significantly greater impact on the results of operations and cash flows of the Underlying Properties than if the operations were more diversified.
 
The receipt of payments by Enduro Sponsor based on the hedge contracts depends upon the financial position of the hedge contract counterparties. A default by any of the hedge contract counterparties could reduce the amount of cash available for distribution to the trust unitholders.
 
Payments from hedge contract counterparties to Enduro Sponsor are intended to offset costs and thus have the effect of providing additional cash to the trust during periods of lower crude oil prices. In the event that any of the counterparties to the hedge contracts default on their obligations to make payments to Enduro Sponsor under the hedge contracts, the cash distributions to the trust unitholders could be materially reduced. Enduro Sponsor does not have any security interest from its hedge counterparties against which it could recover in the event of a default by any such counterparty.
 
Tax Risks Related to the Trust Units
 
The tax treatment of an investment in trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis.
 
The recently enacted Health Care and Education Affordability Reconciliation Act of 2010 includes a provision that, in taxable years beginning after December 31, 2012, subjects an individual having modified adjusted gross income in excess of $200,000 (or $250,000 for married taxpayers filing joint returns) to a “Medicare tax” equal generally to 3.8% of the lesser of such excess or the individual’s net investment income, which appears to include royalty income, if any, derived from the trust units as well as any net gain from the disposition of trust units. In addition, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.
 
The trust has not requested a ruling from the IRS regarding the tax treatment of the trust. If the IRS were to determine (and be sustained in that determination) that the trust is not a “grantor trust” for federal income tax purposes, the trust could be subject to more complex and costly tax reporting requirements that could reduce the amount of cash available for distribution to trust unitholders.
 
If the trust were not treated as a grantor trust for federal income tax purposes, the trust should be treated as a partnership for such purposes. Although the trust would not become subject to federal income taxation at the entity level as a result of treatment as a partnership, and items of income, gain, loss and deduction would flow through to the trust unitholders, the trust’s tax reporting requirements would be more complex and costly to implement and maintain, and its distributions to trust unitholders could be reduced as a result.
 
Neither Enduro Sponsor nor the trustee has requested a ruling from the IRS regarding the tax status of the trust, and neither Enduro Sponsor nor the trust can assure you that such a ruling would be granted if requested or that the IRS will not challenge these positions on audit.


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Trust unitholders should be aware of the possible state tax implications of owning trust units. Please read “State Tax Considerations.”
 
Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.
 
Among the changes contained in President Obama’s Budget Proposal for Fiscal Year 2012 (the “Budget Proposal”) is the elimination of certain key U.S. federal income tax preferences relating to oil and natural gas exploration and production. The Budget Proposal proposes to eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for United States production activities and (iv) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for, or development of, oil or gas within the United States. It is unclear whether any such changes will actually be enacted into law or, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals, or any other similar changes in U.S. federal income tax laws that eliminate certain tax preferences that are currently available with respect to oil and natural gas exploration and production, could reduce the cash available for distribution to the trust unitholders or adversely affect the value of the trust units.
 
You will be required to pay taxes on your share of the trust’s income even if you do not receive any cash distributions from the trust.
 
Trust unitholders are treated as if they own the trust’s assets and receive the trust’s income and are directly taxable thereon as if no trust were in existence. Because the trust will generate taxable income that could be different in amount than the cash the trust distributes, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of the trust’s taxable income even if you receive no cash distributions from the trust. You may not receive cash distributions from the trust equal to your share of the trust’s taxable income or even equal to the actual tax liability that results from that income.
 
A portion of any tax gain on the disposition of the trust units could be taxed as ordinary income.
 
If you sell your trust units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those trust units. A substantial portion of any gain recognized may be taxed as ordinary income due to potential recapture items, including depletion recapture. Please read “Federal Income Tax Consequences — Tax Consequences to U.S. Trust Unitholders — Disposition of Trust Units.”
 
The trust will allocate its items of income, gain, loss and deduction between transferors and transferees of the trust units each month based upon the ownership of the trust units on the monthly record date, instead of on the basis of the date a particular trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the trust unitholders.
 
The trust will generally allocate its items of income, gain, loss and deduction between transferors and transferees of the trust units each month based upon the ownership of the trust units on the monthly record date, instead of on the basis of the date a particular trust unit is transferred. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the trust should be determined and allocated on a daily or prorated basis, which could require adjustments to the tax returns of the trust unitholders affected by the issue and result in an increase in the administrative expense of the trust in subsequent periods. Please read “Federal Income Tax Consequences — U.S. Federal Income Tax Consequences — Direct Taxation of Trust Unitholders.”


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FORWARD-LOOKING STATEMENTS
 
This prospectus contains “forward-looking statements” about Enduro Sponsor and the trust that are subject to risks and uncertainties. All statements other than statements of historical fact included in this prospectus, including, without limitation, statements under “Prospectus Summary” and “Risk Factors” regarding the financial position, business strategy, production and reserve growth and other plans and objectives for the future operations of Enduro Sponsor and the trust are forward-looking statements. Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. Forward-looking statements are subject to risks and uncertainties and include statements made in this prospectus under “Projected Cash Distributions,” statements pertaining to future development activities and costs, and other statements in this prospectus that are prospective and constitute forward-looking statements.
 
When used in this document, the words “believes,” “expects,” “anticipates,” “intends” or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those discussed elsewhere in this prospectus, could affect the future results of the energy industry in general, and Enduro Sponsor and the trust in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:
 
  •      risks associated with the drilling and operation of oil and natural gas wells;
 
  •      the amount of future direct operating expenses and development expenses;
 
  •      the effect of existing and future laws and regulatory actions;
 
  •      the effect of changes in commodity prices or in alternative fuel prices;
 
  •      the impact of hedge contracts;
 
  •      conditions in the capital markets;
 
  •      competition from others in the energy industry;
 
  •      uncertainty of estimates of oil and natural gas reserves and production; and
 
  •      cost inflation.
 
You should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this prospectus. Enduro Sponsor does not undertake any obligation to release publicly any revisions to the forward-looking statements to reflect events or circumstances after the date of this prospectus or to reflect the occurrence of unanticipated events, unless the securities laws require it to do so.
 
This prospectus describes other important factors that could cause actual results to differ materially from expectations of Enduro Sponsor and the trust, including under the heading “Risk Factors.” All written and oral forward-looking statements attributable to Enduro Sponsor, the trust, or persons acting on behalf of Enduro Sponsor or the trust are expressly qualified in their entirety by such factors.


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USE OF PROCEEDS
 
Enduro Sponsor is offering all of the trust units to be sold in this offering, including the trust units to be sold upon the exercise of the underwriters’ option to purchase additional trust units. Enduro Sponsor expects to receive net proceeds from the sale of 13,200,000 trust units offered by this prospectus of approximately $      million, after deducting underwriting discounts and commissions, structuring fees and offering expenses, and $      million if the underwriters exercise their option to purchase additional trust units in full. Enduro Sponsor is deemed to be an underwriter with respect to the trust units offered hereby.
 
Enduro Sponsor intends to use the net proceeds from this offering, including any proceeds from the exercise of the underwriters’ option to purchase additional trust units, to repay a portion of the borrowings outstanding under its senior secured credit agreement, to make a distribution to its sole member, Enduro Holdings, and to acquire additional oil and natural gas properties in the future for Enduro Sponsor. Enduro Sponsor has not yet identified oil and natural gas properties to be acquired.
 
The table below sets forth these intended uses with the corresponding dollar amounts planned for such use, assuming no exercise of the underwriters’ over-allotment option.
 
         
    Intended Amount
 
Intended Use
  Dedicated to Such Use  
    (in millions)  
 
Repay borrowings outstanding under senior secured credit agreement
  $        
Distribution to sole member of Enduro Sponsor
  $        
Future acquisitions of additional oil and natural gas properties for Enduro Sponsor (none of which have been identified)(1)
  $        
 
 
(1) Future acquisitions will not be made on behalf or for the benefit of the trust.
 
On December 1, 2010 Enduro Sponsor entered into a $500 million senior secured credit agreement, which provides for revolving loans. Borrowings under the revolving credit facility have a maturity date of December 1, 2015 and bear interest at the applicable LIBOR rate, plus applicable margins ranging from 1.75% to 2.75%, or at a base rate, based upon the greatest of (a) the Prime Rate, (b) the Federal Funds Rate plus 0.5%, and (c) LIBOR plus 1%, plus applicable margins ranging from 0.75% to 1.75%.
 
As of June 30, 2011, total borrowings under Enduro Sponsor’s revolving credit facility were $231 million and had a weighted average interest rate of approximately 3.3% for the second quarter of 2011. The current borrowings under the revolving credit facility were incurred to fund the acquisition of the Acquired Properties. Affiliates of certain of the underwriters participating in this offering are lenders under Enduro Sponsor’s senior secured credit agreement and will receive a substantial portion of the proceeds from this offering pursuant to the repayment of a portion of the borrowings thereunder. Please read “Underwriting (Conflicts of Interest) — Conflicts of Interest/FINRA Rules.”


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ENDURO SPONSOR
 
Enduro Sponsor is a privately-held Delaware limited liability company engaged in the production and development of oil and natural gas from properties located in Texas, Louisiana and New Mexico. Enduro Sponsor was formed on March 3, 2010.
 
The Underlying Properties were acquired in three separate transactions and are located in two different geographic regions: the Permian Basin and East Texas/North Louisiana. After giving pro forma effect to the conveyance of the Net Profits Interest to the trust, the offering of the trust units contemplated by this prospectus and the application of the net proceeds as described in “Use of Proceeds,” as of March 31, 2011, Enduro Sponsor would have had total assets of $662.8 million and total liabilities of $107.7 million. For an explanation of the pro forma adjustments, please read “Financial Statements of Enduro Sponsor — Unaudited Pro Forma Financial Statements — Introduction.”
 
The trust units do not represent interests in, or obligations of, Enduro Sponsor.


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Summary Historical and Unaudited Pro Forma Financial, Operating and Reserve Data of Enduro Sponsor
 
The summary historical audited financial data presented below should be read in conjunction with “Information about Enduro Resource Partners LLC (Enduro Sponsor) — Selected Historical and Unaudited Pro Forma Financial, Operating and Reserve Data of Enduro Sponsor” and the accompanying financial statements and related notes of Enduro Sponsor included elsewhere in this prospectus. The summary historical audited financial data of the Predecessor as of December 31, 2009 and 2010 and for each of the years in the three-year period ended December 31, 2010 have been derived from the Predecessor’s audited financial statements. Operations of the Predecessor Properties are deemed to be the “predecessor” of Enduro Sponsor and recorded transactions are shown separately based on the ownership of the Predecessor Properties. EAC owned the Predecessor Properties prior to March 9, 2010, at which time Denbury Resources Inc. acquired the properties in connection with its acquisition of EAC. Enduro Sponsor then acquired the Predecessor Properties on December 1, 2010. Accordingly, the audited financial statements of the Predecessor as of and for the three years ended December 31, 2010 are presented for (i) “Predecessor-EAC” for the years ended December 31, 2008 and 2009 and for the period from January 1, 2010 through March 8, 2010; (ii) “Predecessor-DNR” for the period from March 9, 2010 through November 30, 2010 and (iii) “Enduro Sponsor” for the period from Enduro Sponsor’s inception (March 3, 2010) through December 31, 2010.
 
The summary historical unaudited financial data of Enduro Sponsor as of March 31, 2011 and 2010 and for the three-month period ended March 31, 2011 and 2010 have been derived from Enduro Sponsor’s unaudited interim financial statements. The unaudited financial statements were prepared on a basis consistent with the audited statements and, in the opinion of Enduro Sponsor’s management, include all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the results of Enduro Sponsor for the periods presented.
 
The summary unaudited pro forma financial data as of and for the three months ended March 31, 2011 and for the year ended December 31, 2010 set forth in the following table has been derived from the unaudited pro forma financial statements of Enduro Sponsor included elsewhere in this prospectus. The pro forma adjustments have been prepared as if the acquisition of the Acquired Properties and, with respect to the pro forma as adjusted information, the conveyance of the Net Profits Interest and the offer and sale of the trust units and application of the net proceeds therefrom, had taken place (i) on March 31, 2011, in the case of the pro forma balance sheet information as of March 31, 2011, and (ii) as of January 1, 2010, in the case of the pro forma statements of earnings for the three months ended March 31, 2011 and for the year ended December 31, 2010.
 
                                                                                               
          Enduro
                                                             
          Sponsor
          Enduro
                                                 
    Enduro
    Pro Forma as
    Enduro
    Sponsor
                                                 
    Sponsor
    Adjusted for
    Sponsor
    Pro Forma as
                                                 
    Pro Forma
    the Offering
    Pro Forma
    Adjusted for
                                                 
    for the
    (Including the
    for the
    the Offering
                                                 
    Acquisition
    Conveyance
    Acquisition
    (Including the
                                                 
    of the
    of the
    of the
    Conveyance
                                                 
    Acquired
    Net Profits
    Acquired
    of the
    Enduro Sponsor       Enduro Sponsor               Predecessor-EAC  
    Properties     Interest)     Properties     Net Profits Interest)                           Predecessor-DNR       January 1,
             
    Three Months
    Three Months
    Year
    Year
    Three Months
    Inception
      Inception
      March 9, 2010
      2010
             
    Ended
    Ended
    Ended
    Ended
    Ended
    Through
      Through
      Through
      Through
             
    March 31,
    March 31,
    December 31,
    December 31,
    March 31,
    March 31,
      December 31,
      November 30,
      March 8,
    Year Ended December 31,  
    2011     2011     2010     2010     2011     2010       2010       2010       2010     2009     2008  
(In thousands)   (Unaudited)     (Unaudited)     (Unaudited)     (Unaudited)     (Unaudited)     (Unaudited)                                      
                                                                                               
Revenues
  $ 33,793     $ 31,672     $ 137,712     $ 127,421     $ 22,952     $       $ 3,975       $ 40,210       $ 12,164     $ 33,907     $ 62,370  
                                                                                               
Net income (loss)
  $ (9,559 )   $ (6,601 )   $ (8,645 )   $ 2,917     $ (11,495 )   $ (77 )     $ (8,222 )     $ (19,515 )     $ (17,821 )   $ (25,853 )   $ 19,540  
                                                                                               
Total assets (at period end)
          $ 662,829                     $ 735,806     $ 100       $ 361,832       $ 397,314       $ 313,106     $ 301,127     $ 256,783  
                                                                                               
Long-term liabilities, excluding current maturities (at period end)
          $ 77,392                     $ 260,392     $       $ 66,211       $ 587       $ 1,412     $ 1,404     $ 1,322  
                                                                                               
Members’ equity/owners’ equity
          $ 555,166                     $ 445,143     $ 23       $ 273,939       $ 374,731       $ 290,073     $ 281,439     $ 234,433  


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The table below includes selected historical production and reserve information for Enduro Sponsor for the periods presented.
 
                                                         
      Enduro Sponsor     Predecessor-DNR     Predecessor - EAC
      Inception
    Inception
    March 9, 2010
    January 1
       
      Through
    Through
    Through
    Through
  Year Ended
      March 31,
    December 31,
    November 30,
    March 8,
  December 31,
      2010     2010     2010     2010   2009   2008
Production (MBoe)
              143         1,505         329       1,463       1,194  
Net proved reserves (MBoe) (at period end)
              16,432         18,059         17,936       18,265       10,357  
Net proved developed reserves (MBoe) (at period end)
              10,667         9,679         8,685       9,014       7,836  
 
Management of Enduro Sponsor
 
Set forth in the table below are the names, ages and titles of the managers and executive officers of Enduro Sponsor.
 
         
Name
 
Age
 
Title
 
Jon S. Brumley
  40   President, Chief Executive Officer and Manager
John W. Arms
  44   Executive Vice President, Chief Operating Officer and Manager
Kimberly A. Weimer
  32   Vice President and Chief Financial Officer
Bill R. Pardue
  38   Director, Engineering and Operations
David J. Grahek
  57   Director, Geology
David Leuschen
  60   Manager
Pierre F. Lapeyre, Jr. 
  48   Manager
N. John Lancaster
  43   Manager
I. Jon Brumley
  72   Manager
 
Jon S. Brumley co-founded Enduro Sponsor and has been the President and Chief Executive Officer of Enduro Sponsor and a member of Enduro Sponsor’s board of managers (the “Enduro Sponsor Board”) since March 2010. Mr. Brumley is responsible for the coordination and supervision of exploration and production and the acquisition of Enduro Sponsor’s oil and natural gas reserves. Mr. Brumley was the Chief Executive Officer of EAC from January 2006 until March 2010 when it was sold to Denbury Resources Inc., a publicly traded exploration and production company. At EAC, Mr. Brumley also served as President from August 2002 until March 2010, a director on the Board of Directors from April 1999 until May 2001 and from November 2001 until March 2010 and Executive Vice President of Business Development and Corporate Secretary from April 1998 until August 2002. Mr. Brumley also served as President and Chief Executive Officer of Encore Energy Partners GP LLC (“Encore GP LLC”), the general partner of Encore Energy Partners LP (“Encore Energy”), a publicly traded master limited partnership whose general partner was owned by EAC from February 2007 until March 2010. Prior to joining EAC, Mr. Brumley held management positions at MESA Petroleum and Pioneer Natural Resources Company. Mr. Brumley received a Bachelor of Business Administration in Marketing from the University of Texas.
 
John W. Arms co-founded Enduro Sponsor and has been the Executive Vice President and Chief Operating Officer of Enduro Sponsor and a member of the Enduro Sponsor Board since March 2010. Mr. Arms is responsible for the coordination and supervision of acquisitions, the engineering, enhancement and exploitation of Enduro Sponsor’s existing properties as well as the engineering analysis and evaluation of its future reserve acquisitions. Prior to joining Enduro Sponsor, Mr. Arms served as Senior Vice President of Acquisitions at EAC and Encore Energy from February 2007 until its acquisition by Denbury Resources Inc. in March 2010. At EAC, Mr. Arms also served as Vice President of Business Development of EAC from September 2001 until February 2007 and as Manager of Acquisitions and in various other petroleum engineering positions from November 1998 until


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September 2001. Prior to joining EAC, Mr. Arms held various positions of responsibility at XTO Energy and ARCO Oil and Gas Company. Mr. Arms received his Bachelor of Science in Petroleum Engineering from the Colorado School of Mines.
 
Kimberly A. Weimer has been the Vice President and Chief Financial Officer of Enduro Sponsor since April 2010. Prior to joining Enduro Sponsor, Ms. Weimer served as the Director of Investor Relations of EAC from October 2008 until its acquisition by Denbury Resources Inc. in March 2010. From May 2007 until October 2008, she was the Senior Manager of Financial Reporting at EAC responsible for all aspects of SEC reporting for Encore Energy. During this timeframe, Encore Energy completed its initial public offering and was listed on the New York Stock Exchange, completed two follow-on equity offerings, and purchased over $500 million in assets. Prior to joining EAC in 2007, Ms. Weimer worked in public accounting, beginning her career at Arthur Andersen. From May 2005 to May 2007, Ms. Weimer served as an Audit Manager at Cherry, Bekaert & Holland. Ms. Weimer received a Bachelor of Science in Accounting and Finance from Louisiana State University. She is a Certified Public Accountant.
 
Bill R. Pardue has been the Director, Engineering and Operations of Enduro Sponsor since May 2010. Prior to joining Enduro Sponsor, Mr. Pardue served as the Asset Manager of Encore Energy from May 2007 to May 2010. Mr. Pardue also served as the Engineering Manager for EAC from June 2005 until May 2007 in the Permian and Mid-Continent regions. At EAC, Mr. Pardue also worked in various petroleum engineering positions from November 2000 until May 2005. Prior to joining EAC, Mr. Pardue worked as a production and reservoir engineer for Meridian Oil/Burlington Resources from 1996 until 2000. Mr. Pardue received a Bachelor of Science in Petroleum Engineering from Texas Tech University and a Master of Business Administration from Texas Christian University. Mr. Pardue is also a registered professional engineer in the state of Texas.
 
David J. Grahek has been the Director, Geology of Enduro Sponsor since June 2010. Prior to joining Enduro Sponsor, Mr. Grahek served as Geologic Advisor of EAC from June 2005 until its acquisition by Denbury Resources, Inc. in March 2010. Prior to joining EAC, Mr. Grahek held various positions of responsibility with G&G Exploration Inc. and Union Pacific Resources Company. Mr. Grahek has over 35 years of petroleum geology experience. Mr. Grahek received his Bachelor of Science in Geology from the University of Southern Colorado and completed post graduate work at the Colorado School of Mines.
 
David Leuschen has been a member of the Enduro Sponsor Board since March 2010. Mr. Leuschen is a founder and Senior Managing Director of Riverstone. Prior to co-founding Riverstone, Mr. Leuschen was a Partner and Managing Director at Goldman, Sachs & Co. and founder and head of the Goldman, Sachs & Co. Global Energy & Power Group. Mr. Leuschen joined Goldman, Sachs & Co. in 1977 and became head of the Global Energy & Power Group in 1985 and a Partner in 1986. He remained with Goldman, Sachs & Co. until leaving to found Riverstone. Mr. Leuschen has served as a director of Cambridge Energy Research Associates, Cross Timbers Oil Company (predecessor to XTO Energy), J. Aron Resources, Mega Energy, Inc. and Natural Meats Montana. He currently serves on the boards of directors of Legend Natural Gas, Dynamic Industries, Dynamic Offshore Resources, Titan Operating, Northern Blizzard and Barra Energia. He is also president of Switchback Ranch LLC and has served on a number of non-profit boards of directors. Mr. Leuschen received his Bachelor of Arts from Dartmouth and his Master of Business Administration from Dartmouth’s Amos Tuck School of Business.
 
Pierre F. Lapeyre, Jr. has been a member of the Enduro Sponsor Board since March 2010. Mr. Lapeyre is a founder and Senior Managing Director of Riverstone. Prior to co-founding Riverstone, Mr. Lapeyre was a Managing Director at Goldman, Sachs & Co. in its Global Energy & Power Group. Mr. Lapeyre joined Goldman, Sachs & Co. in 1986 and spent his 14-year investment banking career focused on energy and power, particularly the midstream/pipeline and oil service sectors. Mr. Lapeyre’s responsibilities included client coverage and leading the execution of a wide variety of mergers and acquisitions, initial public offerings, strategic advisory and capital markets financings for clients across all sectors of the industry. Mr. Lapeyre serves on the boards of directors of Legend Natural Gas, Titan


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Specialties, Dynamic Industries, Titan Operating, Three Rivers, Northern Blizzard, Dynamic Offshore Resources and Quorum Technologies. Mr. Lapeyre received his Bachelor of Science in Finance and Economics from the University of Kentucky and his Master of Business Administration from the University of North Carolina at Chapel Hill.
 
N. John Lancaster has been a member of the Enduro Sponsor Board since March 2010. Mr. Lancaster is a Partner and Managing Director of Riverstone. Mr. Lancaster joined Riverstone in 2000 and is responsible for the sourcing and management of investments across the energy industry, with a particular emphasis on the oilfield service and exploration and production sectors. Prior to joining Riverstone, Mr. Lancaster was a Director with The Beacon Group, LLC, a privately held firm specializing in principal investing and strategic advisory services in the energy and other industries. Mr. Lancaster began his career at Bankers Trust and later at CS First Boston, spending time as an investment banker and equity research analyst focused on the oil service and unregulated gas transmission sectors of the energy industry. Mr. Lancaster serves on the boards of directors of Cobalt International, Titan Specialties, Dynamic Industries, Dynamic Offshore Resources, Cuadrilla Resources, Hudson Products, Liberty Resources, and Barra Energia. Mr. Lancaster received his Bachelor of Business Administration from the University of Texas, where he serves on the McCombs School of Business Advisory Council, and his Master of Business Administration from Harvard Business School.
 
I. Jon Brumley has been a member of the Enduro Sponsor Board since March 2010. Mr. Brumley served as the Chairman of the Board of Directors of Encore GP LLC from February 2007 to March 2010. Mr. Brumley also served as the Chairman of the Board of Directors of EAC since its inception in April 1998 until March 2010, the Chief Executive Officer from its inception until December 2005 and President from its inception until August 2002. Beginning in August 1996, Mr. Brumley served as Chairman and Chief Executive Officer of MESA Petroleum until MESA’s merger in August 1997 with Parker & Parsley to form Pioneer Natural Resources Company. He served as Chairman and Chief Executive Officer of Pioneer until joining EAC in 1998. Mr. Brumley received a Bachelor of Business Administration from the University of Texas and a Master of Business Administration from the University of Pennsylvania Wharton School of Business.


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Beneficial Ownership of Enduro Sponsor
 
The following table sets forth, as of July 25, 2011, the beneficial ownership of limited liability company interests of Enduro Sponsor held by:
 
  •      each person who beneficially owns 5% or more of the outstanding membership interests in Enduro Sponsor;
 
  •      each manager and executive officer of Enduro Sponsor; and
 
  •      all managers and executive officers of Enduro Sponsor as a group.
 
Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all membership interests of Enduro Sponsor shown as beneficially owned by them and their address is 777 Main Street, Suite 800, Fort Worth, Texas 76102.
 
         
    Percentage of
    Membership
    Interests
    Beneficially
Name of Beneficial Owner
  Owned
 
Enduro Resource Holdings LLC(1)
    100 %
Jon S. Brumley
     
David Leuschen
     
Pierre F. Lapeyre, Jr. 
     
N. John Lancaster
     
I. Jon Brumley
     
John W. Arms
     
Kimberly A. Weimer
     
Bill R. Pardue
     
David J. Grahek
     
Managers and executive officers of Enduro Sponsor as a group (9 persons)
     
 
 
(1) Enduro Resource Holdings LLC is owned by individual investors, including certain of the directors and executive officers of Enduro Sponsor, and by R/C IV Enduro Holdings, L.P. (“R/C IV Enduro”) and End Line Partners LP (“End Line”). As of July 25, 2011, the beneficial ownership of limited liability company interests of Enduro Holdings is as follows:
 
         
    Percentage of
    Membership
    Interests
    Beneficially
Name of Beneficial Owner
  Owned
 
R/C IV Enduro Holdings, L.P.(a)
    92.7 %
End Line Partners LP(b)
    5.0 %
Jon S. Brumley
    *  
David Leuschen
    *  
Pierre F. Lapeyre, Jr. 
    *  
I. Jon Brumley
    *  
John W. Arms
    *  
Kimberly A. Weimer
    *  
Bill R. Pardue
    *  
David J. Grahek
    *  
 
 
 * Less than 1%.


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(a) R/C IV Enduro is the record holder of approximately 92.7% of the limited liability company interests of Enduro Holdings. R/C Energy GP IV, LLC (“R/C Energy GP”) exercises investment discretion and control over the units held by R/C IV Enduro through its subsidiary, Riverstone/Carlyle Energy Partners IV, L.P. (“Riverstone/Carlyle Energy”), which is the general partner of R/C IV Enduro. Accordingly, each of Riverstone/Carlyle Energy and R/C Energy GP may be deemed to be beneficial owners of the units owned of record by R/C IV Enduro.
 
R/C Energy GP is managed by a board of managers and all action relating to the voting or disposition of the units in Enduro Holdings requires approval of a majority of the board of managers. Pierre F. Lapeyre, Jr., David M. Leuschen, Lord John Browne, Michael B. Hoffman, N. John Lancaster, Jr., Andrew W. Ward, Daniel A. D’Aniello and Edward J. Mathias, as the managing members of R/C Energy GP, may be deemed to share beneficial ownership of the units in Enduro Holdings beneficially owned by R/C Energy GP. Such individuals expressly disclaim any such beneficial ownership. The principal address of each of R/C Energy GP, Riverstone/Carlyle Energy and R/C IV Enduro is c/o Riverstone Holdings LLC, 712 Fifth Avenue, 51st Floor, New York, New York 10019.
 
(b) End Line is the record holder of approximately 5% of the limited liability company interests of Enduro Holdings. End Line is managed by its general partner, Bratton Capital Management, L.P., which is managed by its general partner, Bratton Capital Inc. The address for End Line is c/o Crestline Investors, Inc., 201 Main Street, Suite 1900, Fort Worth, Texas 76102.
 
Beneficial Ownership of Enduro Royalty Trust
 
The following table sets forth the beneficial ownership of trust units of the trust that will be outstanding after giving effect to the consummation of this offering, assuming no exercise of the underwriters’ option to purchase additional trust units, and held, directly or indirectly, by each person who will then beneficially own 5% or more of the outstanding trust units.
 
             
    Class of
  Percentage of
Name of Beneficial Owner
  Securities   Ownership
 
Enduro Sponsor
  Trust Units     60 %


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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
 
The trust will enter into a registration rights agreement with Enduro Sponsor in connection with Enduro Sponsor’s contribution to the trust of the Net Profits Interest. Under the registration rights agreement, the trust will agree, for the benefit of Enduro Sponsor and any transferee of Enduro Sponsor’s trust units, to register the trust units they hold. In connection with the preparation and filing of any registration statement, Enduro Sponsor will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the trust, which will be borne by the trust. Any underwriting discounts and commissions will be borne by the seller of the trust units. Please read “Trust Units Eligible for Future Sale — Registration Rights.”


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THE TRUST
 
The trust is a statutory trust created under the Delaware Statutory Trust Act on May 3, 2011. The affairs of the trust will be managed by The Bank of New York Mellon Trust Company, N.A., as trustee. Enduro Sponsor has no ability to manage or influence the operations of the trust. In addition, Wilmington Trust Company will act as Delaware trustee of the trust. The Delaware trustee will have only minimal rights and duties as are necessary to satisfy the requirements of the Delaware Statutory Trust Act. In connection with the completion of this offering, Enduro Sponsor will contribute the Net Profits Interest to the trust in exchange for 33,000,000 newly issued trust units. Enduro Sponsor will make its first payment to the trust pursuant to the Net Profits Interest in October 2011, which payment may include cash that Enduro Sponsor is required to pay to the trust relating to sales of oil and natural gas production for the months of May and June 2011 and production and development expenses for the months of May and June 2011. Subsequent distributions will only cover the net profits attributable to the Net Profits Interest for one month, and, as a result, are likely to differ substantially.
 
The trustee can authorize the trust to borrow money to pay trust administrative or incidental expenses that exceed cash held by the trust. The trustee may authorize the trust to borrow from the trustee as a lender provided the terms of the loan are fair to the trust unitholders. The trustee may also deposit funds awaiting distribution in an account with itself, if the interest paid to the trust at least equals amounts paid by the trustee on similar deposits, and make other short-term investments with the funds distributed to the trust. The trustee has no current plans to authorize the trust to borrow money.
 
The trust will pay the trustee and Delaware trustee an administrative fee of $200,000 and $2,000 per year, respectively. The trust will also incur legal, accounting, tax, advisory and engineering fees, printing costs and other administrative and out-of-pocket expenses that are deducted by the trust before distributions are made to trust unitholders. The trust will also be responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual, quarterly and monthly reports to trust unitholders, tax return and Form 1099 preparation and distribution, NYSE listing fees, independent auditor fees and registrar and transfer agent fees. Total administrative expenses of the trust on an annualized basis for 2011 are initially expected to be approximately $850,000, including the administrative fees payable to the trustee and Delaware trustee.
 
The trust will dissolve upon the earliest to occur of the following: (1) the trust, upon the approval of the holders of at least 75% of the outstanding trust units, sells the Net Profits Interest, (2) the annual cash available for distribution to the trust is less than $2 million for each of any two consecutive years, (3) the holders of at least 75% of the outstanding trust units vote in favor of dissolution or (4) the trust is judicially dissolved.


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PROJECTED CASH DISTRIBUTIONS
 
Immediately prior to the closing of this offering, Enduro Sponsor will create the Net Profits Interest through a conveyance to the trust of a Net Profits Interest carved from Enduro Sponsor’s interests in certain of its oil and natural gas properties located in Texas, Louisiana and New Mexico. The Net Profits Interest will entitle the trust to receive 80% of the net profits from the sale of production of oil and natural gas attributable to the Underlying Properties.
 
The amount of trust revenues and cash distributions to trust unitholders will depend on, among other things:
 
  •      oil and natural gas sales prices;
 
  •      the volume of oil and natural gas produced and sold attributable to the Underlying Properties;
 
  •      the payments made or received by Enduro Sponsor pursuant to the hedge contracts;
 
  •      direct operating expenses;
 
  •      development expenses; and
 
  •      administrative expenses of the trust.
 
The following table presents a calculation of forecasted cash distributions to holders of trust units for the twelve months ending September 30, 2012, which was prepared by Enduro Sponsor based on the assumptions that are described below and in “— Significant Assumptions Used to Prepare the Projected Cash Distributions.”
 
Typically, cash payment is received by Enduro Sponsor for oil production 30 to 60 days after it is produced and for natural gas production 60 to 90 days after it is produced. Given that the trust is entitled to production effective May 1, 2011 and the initial distribution will not occur until October 2011, the initial distribution in October 2011 may relate to net profits received from production from May and June of 2011. The forecasted cash distributions assume that each of the monthly distributions during the forecasted period will relate to production from a single month. To adjust for the lag between the timing of production and the timing of cash received by Enduro Sponsor and the trust, the forecasted cash distributions for the twelve months ending September 30, 2012 are based on estimated production of oil and natural gas for the twelve months ending April 30, 2012.
 
Unlike payments for production, payments related to hedges are settled during or very soon after the end of each month. As a result, and in an effort to better align payments associated with production and hedges, the trust will not bear any hedge settlement costs paid by Enduro Sponsor, or be entitled to any hedge payments received by Enduro Sponsor, for periods on or prior to June 30, 2011 (which is 60 days after May 1, 2011). In order to reflect this, the forecasted cash distributions for the twelve months ending September 30, 2012 reflect forecasted hedge settlements related to the twelve months ending June 30, 2012.
 
Enduro Sponsor does not as a matter of course make public projections as to future sales, earnings or other results. However, the management of Enduro Sponsor has prepared the projected financial information set forth below to present the projected cash distributions to the holders of the trust units based on the estimates and hypothetical assumptions described below. The accompanying projected financial information was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to projected financial information.
 
In the view of Enduro Sponsor’s management, the accompanying unaudited projected financial information was prepared on a reasonable basis and reflects the best currently available estimates and


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judgments of Enduro Sponsor related to oil and natural gas production, operating expenses and development expenses and other general and administrative expenses based on:
 
  •      the oil and natural gas production estimates for the twelve months ending April 30, 2012 contained in the reserve reports;
 
  •      estimated direct operating expenses and development expenses for the twelve months ending April 30, 2012 contained in the reserve reports;
 
  •      projected payments made or received pursuant to the hedge contracts for the twelve months ending June 30, 2012;
 
  •      estimated general and administrative expenses of $850,000 for the twelve months ending April 30, 2012; and
 
  •      an adjustment for the estimated production, revenue, operating expenses and development expenses (as adjusted to reflect that Enduro Sponsor has agreed to pay for $7.3 million of development expenses otherwise attributable to the trust) expected in the twelve months ending April 30, 2012 for drilling projects in the Haynesville Shale that are not included in the reserve reports.
 
The projected financial information was also based on the hypothetical assumption that prices for oil and natural gas remain constant at $100.00 per Bbl of oil and $4.50 per MMBtu of natural gas during the twelve months ending April 30, 2012. These hypothetical prices are then adjusted to take into account Enduro Sponsor’s estimate of the basis differential (based on location and quality of the production) between published prices and the prices actually received by Enduro Sponsor. Actual prices paid for oil and natural gas expected to be produced from the Underlying Properties during the twelve months ending April 30, 2012 will likely differ from these hypothetical prices due to fluctuations in the prices generally experienced with respect to the production of oil and natural gas and variations in basis differentials. For example, for the twelve months ending June 30, 2011, the published daily average closing WTI crude oil spot price per Bbl was approximately $89.40 and the daily average Henry Hub natural gas spot price per MMBtu was approximately $4.16.
 
Please read “— Significant Assumptions Used to Prepare the Projected Cash Distributions” and “Risk Factors — Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the trust and cash distributions to trust unitholders.”
 
Neither Enduro Sponsor’s independent auditors nor any other independent accountants have compiled, examined or performed any procedures with respect to the projected financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the projected financial information.
 
The projections and estimates and the hypothetical assumptions on which they are based are subject to significant uncertainties, many of which are beyond the control of Enduro Sponsor or the trust. Actual cash distributions to trust unitholders, therefore, could vary significantly based upon events or conditions occurring that are different from the events or conditions assumed to occur for purposes of these projections. Cash distributions to trust unitholders will be particularly sensitive to fluctuations in oil and natural gas prices. Please read “Risk Factors — Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the trust and cash distributions to trust unitholders.” As a result of typical production declines for oil and natural gas properties, production estimates generally decrease from year to year, and the projected cash distributions shown in the table below are not necessarily indicative of distributions for future years. Please read “— Sensitivity of Projected Cash Distributions to Oil and Natural Gas Production and Prices” below, which shows projected effects on cash distributions from hypothetical changes in oil and natural gas production and prices. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the Underlying Properties diminishing over time, a portion of each


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distribution will represent, in effect, a return of your original investment. Please read “Risk Factors — The reserves attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production. Therefore, proceeds to the trust and cash distributions to trust unitholders will decrease over time.”
 
         
    Projections for the
 
    Twelve Month Period
 
    Ending September 30,
 
Projected Cash Distributions to Trust Unitholders
  2012  
    (In thousands, except per unit data)  
 
Underlying Properties sales volumes:
       
Oil (MBbl)(1)
    911  
Natural gas (MMcf)
    7,119  
         
Total sales (MBoe)
    2,097  
         
Assumed NYMEX price(2):
       
Oil (per Bbl)
  $ 100.00  
Natural gas (per MMBtu)
    4.50  
Assumed realized sales price(3):
       
Oil (per Bbl)
  $ 96.54  
Natural gas (per Mcf)
    4.63  
Calculation of net profits:
       
Gross profits(4):
       
Oil sales
  $ 87,940  
Natural gas sales
    32,979  
         
Total
  $ 120,919  
         
Costs:
       
Direct operating expenses:
       
Lease operating expenses
  $ 23,489  
Production and other taxes
    9,225  
Development expenses(5)
    14,300  
         
Total
  $ 47,014  
         
Settlement of hedge contracts(6)
    1,857  
         
Net adjustment for additional projects(7)
    (989 )
Net profits
  $ 74,773  
Percentage allocable to Net Profits Interest
    80%  
         
Net profits to trust from Net Profits Interest
  $ 59,818  
Trust general and administrative expenses(8)
  $ 850  
         
Cash available for distribution by the trust
  $ 58,968  
         
Cash distribution per trust unit (assumes 33,000,000 units)
  $ 1.79  
         
 
 
(1) Sales volumes for oil include 9 MBbls of NGLs.
 
(2) For a description of the effect of lower NYMEX prices on projected cash distributions, please read “— Sensitivity of Projected Cash Distributions to Oil and Natural Gas Production and Prices.”
 
(3) Sales price net of forecasted gravity, quality, transportation, gathering and processing and marketing costs. For more information about the estimates and hypothetical assumptions made in preparing the table above, see “— Significant Assumptions Used to Prepare the Projected Cash Distributions.”
 
(4) Represents “gross profits” as described in “Computation of Net Profits.”
 
(5) Does not include development expenses related to 21 gross (2.4 net) wells associated with development drilling projects in the Haynesville Shale. Please read footnote 7.


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(6) Reflects net cash impact of settlements of hedge contracts relating to production. See “The Underlying Properties — Hedge Contracts.”
 
(7) Net adjustment for additional projects reflects the expected drilling of 21 gross (2.4 net) wells in the Haynesville Shale during the forecast period associated with development drilling projects not reflected in the reserve reports but for which notifications have been received by Enduro Sponsor as of June 2011. These additional development drilling projects are expected to increase total sales volumes by 221 MBoe, total gross profits by $3.3 million and total lease operating and development expenses and production and other taxes by $4.3 million, which is expected to result in a decrease in net profits for the Underlying Properties by $989,000 and cash available for distribution to the trust by $791,000. The amount of estimated development expenses has been adjusted to reflect the agreement by Enduro Sponsor to pay for up to $9.1 million (or $7.3 million attributable to the trust’s Net Profits Interest) of the total estimated development expenses of $12.4 million related to the 21 gross (2.4 net) wells, thereby reducing the trust’s share of development expenses associated with these wells to $2.6 million. In the absence of this payment obligation by Enduro Sponsor, the cash available for distribution to the trust would be reduced by an additional $7.3 million during the forecast period. Please read “Projected Cash Distributions — Significant Assumptions Used to Prepare the Projected Cash Distributions — Net adjustment for additional projects.”
 
(8) Total general and administrative expenses of the trust on an annualized basis for the twelve months ending April 30, 2012 are expected to be $850,000 and will include the annual fees to the trustees, accounting fees, engineering fees, legal fees, printing costs and other expenses properly chargeable to the trust.
 
Significant Assumptions Used to Prepare the Projected Cash Distributions
 
Timing of actual distributions.  In preparing the projected cash distributions above and sensitivity analysis below, the revenues and expenses of the trust were calculated based on the terms of the conveyance creating the trust’s Net Profits Interest. These calculations are described under “Computation of Net Profits Interest.” It is the intent of the trust to distribute to trust unitholders proceeds received by the trust in the month after the trust receives such funds. Monthly cash distributions will be made to holders of trust units as of the applicable record date (generally the 15th day of each calendar month) on or before the 10th business day after the record date. Due to the amount of time it typically takes the Third Party Operators to collect payments from their customers and distribute their payments to the interest owners, including Enduro Sponsor, it has been assumed, for purposes of the projections, that cash distributions for each month will include oil production from 60 to 90 days prior to the distribution date and natural gas production from 90 to 120 days prior to the distribution date. The first distribution is expected to be made on or about October 28, 2011 to record trust unitholders as of or about October 14, 2011, and may include cash that Enduro Sponsor is required to pay to the trust relating to sales of oil and natural gas production for the months of May and June 2011 and production and development expenses for the months of April and May 2011.
 
Production estimates and development expenses.  In 2009 and 2010, Enduro Sponsor’s production declines were 5.4% and 12%, respectively, and for the year ended December 31, 2010, net sales were 939 MBbls of oil and 7,171 MMcf of natural gas. Based on the reserve reports, production volumes for the twelve months ending April 30, 2012 (the “forecast period”) are 911 MBbls of oil and 7,119 Mcf of natural gas, representing a decline in production of 1.7% for the forecast period from 2010 production. Historically, Enduro Sponsor’s decline rate has been much greater. This difference is due to increased vertical infill drilling of tight sands in the Hosston and Cotton Valley formations in the East Texas/North Louisiana region in 2008 and 2009. Despite the drilling of 1.3 net wells and 1.1 net wells in 2009 and 2010, respectively, this was insufficient to offset the decline from the drilling of 21.9 net wells in the Elm Grove field in 2008.
 
In 2010, 11 gross (1.0 net) wells were horizontally drilled in the Haynesville Shale formation on the Underlying Properties. As of July 25, 2011, Enduro Sponsor was participating in 26 gross (2.5 net)


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horizontal Haynesville Shale wells in the Kingston and Elm Grove fields in the East Texas/North Louisiana region. According to the Third Party Operators, future development drilling will be increasingly focused on the horizontal Haynesville Shale and Lower Cotton Valley. Please see “The Underlying Properties — Near Term Development Activities” for more information regarding drilling activities in the Haynesville Shale. The impact of horizontal drilling can be large with initial producing rates up to 15 MMcf per day. Thus, although the 2010 Haynesville drilling activity was not large enough to sufficiently impact the character or decline of Enduro Sponsor’s proved developed production, future drilling activity in the Haynesville Shale is expected to shallow the overall 2011 and 2012 producing decline rates (as represented in the forecast period).
 
The proved undeveloped reserves scheduled in the Underlying Properties reserve report for 2011 through 2015 have modeled future drilling with 29 proved undeveloped Haynesville Shale and Lower Cotton Valley wells, along with 8 proved undeveloped Lost Tank field wells. Without any future drilling, the reserve report relating to the Underlying Properties reflects a proved developed producing decline rate for 2011, 2012, 2013, 2014 and 2015 of 16%, 14%, 12%, 9% and 9%, respectively. With the development of the proved undeveloped Haynesville Shale and Lower Cotton Valley wells in the reserve report, Enduro Sponsor expects an average increase of 1% on production from 2011 through 2015. For further information, please see the five-year production graph in “Prospectus Summary — Enduro Royalty Trust” and “The Underlying Properties — Near Term Development Activities.”
 
Oil and natural gas prices.  Assumed NYMEX oil and natural gas prices differ from the actual price received for production attributable to the Underlying Properties. Differentials between published oil and natural gas prices and the prices actually received for the oil and natural gas production may vary significantly due to market conditions, transportation, gathering and processing costs, quality of production and other factors.
 
In the above table, an average of $3.46 per Bbl is deducted from, and an average of $0.13 per Mcf is added to, the assumed NYMEX futures price for crude oil and natural gas, respectively, to reflect these differentials. These differences are based on Enduro Sponsor’s estimate of the average difference between the NYMEX published price of crude oil and natural gas and the price to be received by Enduro Sponsor for production attributable to the Underlying Properties during the twelve months ending April 30, 2012. Projected average oil and natural gas prices appearing in this prospectus have been adjusted for these differentials.
 
The differentials to published oil and natural gas prices applied in the above projected cash distribution estimate are based upon an analysis by Enduro Sponsor of the historic price differentials for production from the Underlying Properties with consideration given to gravity, quality and transportation and marketing costs that may affect these differentials. There is no assurance that these assumed differentials will occur.
 
When oil and natural gas prices decline, the operators of the properties comprising the Underlying Properties may elect to reduce or completely suspend production. No adjustments have been made to estimated production during the twelve months ending April 30, 2012 to reflect potential reductions or suspensions of production.
 
Settlement of Hedge Contracts.  Enduro Sponsor has entered into commodity derivative contracts with unaffiliated third parties in order to mitigate the effects of falling commodity prices through 2013. The trust will not bear any hedge settlement costs paid by Enduro Sponsor, or be entitled to any hedge payments received by Enduro Sponsor, for periods on or prior to June 30, 2011. For more information, see “The Underlying Properties — Hedge Contracts.”
 
Costs.  For the twelve months ending April 30, 2012, Enduro Sponsor estimates lease operating expenses to be approximately $23.4 million, production and other taxes to be approximately $9.2 million and development costs incurred to be approximately $14.0 million. For the year ended December 31, 2010, lease operating expenses of the Underlying Properties were $24.6 million, property and other taxes were $8.1 million and development costs incurred were $37.0 million. Enduro Sponsor


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believes drilling activity during the year ended December 31, 2010 was in excess of that which will be undertaken in each of the next five years. For a description of direct operating expenses, see “Computation of Net Profits — Net Profits Interest.”
 
Net adjustment for additional projects.  Net adjustment for additional projects reflects the expected drilling of 21 gross (2.4 net) wells in the Haynesville Shale during the forecast period associated with development drilling projects not reflected in the reserve reports but for which notifications have been received by Enduro Sponsor as of June 2011 and as identified in the conveyance relating to the Net Profits Interest. The additional wells are expected to increase total sales volumes for the Underlying Properties during the forecast period by 221 MBoe. In estimating the production attributable to the Haynesville Shale projects discussed above, Enduro Sponsor used the same methodologies and assumptions as were used in the preparation of the reserve reports by Cawley Gillespie. During the forecast period, the additional wells are expected to increase total gross profits with respect to the Underlying Properties by approximately $3.3 million and total lease operating and development expenses and production and other taxes by $4.3 million, which is expected to result in a decrease in net profits for the Underlying Properties by $989,000 and cash available for distribution to the trust by $791,000. The amount of estimated development expenses has been adjusted to reflect the agreement by Enduro Sponsor to pay for up to $9.1 million (or $7.3 million attributable to the trust’s Net Profits Interest) of the total estimated development expenses of $12.4 million related to the 21 gross (2.4 net) wells, thereby reducing the trust’s share of development expenses associated with these wells to $2.6 million. In the absence of this payment obligation by Enduro Sponsor, the cash available for distribution to the trust would be reduced by an additional $7.3 million during the forecast period. Enduro Sponsor will not pay the trust’s share of any development costs relating to these wells in excess of the amounts described above, so the trust will bear 80% of any incremental development expenses. Enduro Sponsor will also not pay the trust’s share of any development costs for additional wells that may be drilled during the forecast period.
 
General and administrative expense.  The trust will be responsible for paying the annual fees to the trustees, all accounting fees, engineering fees, legal fees, printing costs and other out-of-pocket expenses incurred by or at the direction of the trustee or the Delaware trustee. The trust will also be responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual, quarterly and monthly reports to trust unitholders, tax return and Form 1099 preparation and distribution, NYSE listing fees, independent auditor fees and registrar and transfer agent fees. These general and administrative expenses are anticipated to be approximately $850,000 for the twelve months ending April 30, 2012. General and administrative expenses for subsequent years could be greater or less depending on future events that cannot be predicted. Included in the estimates is an annual administrative fee of $200,000 and $2,000 for the trustee and Delaware trustee, respectively. The trust will pay, out of the first cash payment received by the trust, the trustee’s and Delaware trustee’s legal expenses incurred in forming the trust as well as their acceptance fees in the amount of $10,000 and $1,500, respectively. These costs will be deducted by the trust before distributions are made to trust unitholders. See “The Trust.”
 
Sensitivity of Projected Cash Distributions to Oil and Natural Gas Production and Prices
 
The amount of revenues of the trust and cash distributions to the trust unitholders will be directly dependent on the sales price for oil and natural gas production sold from the Underlying Properties, the volumes of oil and natural gas produced attributable to the Underlying Properties, payments made or received under the hedge contracts and variations in direct operating expenses and development expenses.
 
The table and discussion below set forth sensitivity analyses of annual cash distributions per trust unit for the twelve months ending September 30, 2012, on the assumption that a trust unitholder purchased a trust unit in this offering and held such trust unit until the monthly record date for distributions for September 2012, based upon (1) the assumption that a total of 33,000,000 trust units are issued and outstanding after the closing of the offering made hereby; (2) realization of the


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production levels estimated in the reserve reports; (3) the hypothetical commodity prices based upon assumed NYMEX prices; (4) the impact of the hedge contracts entered into by Enduro Sponsor that relate to production from the Underlying Properties; and (5) other assumptions described above under “— Significant Assumptions Used to Prepare the Projected Cash Distributions.” The hypothetical commodity prices of oil and natural gas production shown have been chosen solely for illustrative purposes.
 
The table below is not a projection or forecast of the actual or estimated results from an investment in the trust units. The purpose of the table below is to illustrate the sensitivity of cash distributions to changes in oil and natural gas pricing (giving effect to the hedge contracts that will be in place during the twelve months ending April 30, 2012). There is no assurance that the hypothetical assumptions described below will actually occur or that NYMEX futures prices will not change by amounts different from those shown in the tables.
 
The trust’s hedge contracts will be in effect only through December 31, 2013, and thus there is likely to be greater fluctuation in cash distributions resulting from fluctuations in the realized oil and natural gas prices in periods subsequent to the expiration of those contracts. See “Risk Factors” for a discussion of various items that could impact production levels and the prices of crude oil and natural gas.
 
Sensitivity of Projected Cash Distribution Per Trust Unit
to Changes in NYMEX Futures Pricing
(Period Estimate of May 2011 to April 2012)
 


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THE UNDERLYING PROPERTIES
 
The Underlying Properties consist of producing and non-producing interests in oil and natural gas units, wells and lands in Texas, Louisiana and New Mexico. The Underlying Properties include a portion of the assets in East Texas and North Louisiana acquired by Enduro Sponsor from Denbury Resources Inc. in December 2010, and all of the assets in the Permian Basin of New Mexico and West Texas acquired by Enduro Sponsor from Samson Investment Company and ConocoPhillips Company in January 2011 and February 2011, respectively. The Underlying Properties are divided into two geographic regions: the Permian Basin region and East Texas/North Louisiana region.
 
As of December 31, 2010, the Underlying Properties had proved reserves of 27.1 MMBoe. A majority of the proved reserves attributable to Underlying Properties are proved developed reserves. Proved developed reserves are the most valuable and lowest risk category of reserves because their production requires no significant future development expenses. As of December 31, 2010, approximately 75% of the volumes and 90% of the PV-10 value of the proved reserves associated with the Underlying Properties were attributed to proved developed reserves. As of December 31, 2010, the Third Party Operators and Enduro Sponsor were the operators of 99% and 1%, respectively, of the proved reserves attributable to the Underlying Properties, based on PV-10 value.
 
As proved reserves are evaluated using only direct costs such as production costs, production taxes, work-over, gathering and processing, transportation and drilling costs, if applicable, and other costs such as general and administrative, depreciation, depletion and amortization, interest and derivative losses are not included, the attribution of proved reserves is not necessarily a sign of future overall corporate profitability.
 
The following table sets forth, as of December 31, 2010, certain estimated proved reserves, estimated future net revenues and the discounted present value thereof attributable to the Underlying Properties, 80% of the Underlying Properties and the Net Profits Interest, in each case derived from the reserve reports.
 
                         
          80% of the
    Net
 
    Underlying
    Underlying
    Profits
 
    Properties(1)     Properties(2)     Interest  
    (In thousands)  
 
Proved Reserves
                       
Oil (MBbls)(3)
    12,766       10,213       5,642  
Natural Gas (MMcf)
    85,787       68,630       43,058  
Oil Equivalents (Mboe)(4)
    27,064       21,651       12,818  
Future Net Revenues
  $ 1,344,718     $ 1,075,774     $ 616,091  
Future Production Cost
  $ 578,014     $ 462,411     $ 48,895 (5)
Future Development Cost
  $ 57,674     $ 46,139     $  
                         
Future Net Income
  $ 709,030     $ 567,196     $ 567,196  
Present Value at 10% Discount Rate(6)
  $ 349,532     $ 279,688     $ 279,688  
Standardized Measure of Discounted Future Net Cash Flows
  $ 349,532     $ 279,688     $ 279,688  
 
 
(1) Reserve volumes and estimated future net revenues for the Underlying Properties reflect volumes and revenues attributable to Enduro Sponsor’s net interests in the properties comprising the Underlying Properties.
 
(2) Reflects 80% of the proved reserves and future net revenues, production and development cost, net income and present value attributable to the Underlying Properties expected to be produced based on the reserve report.


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(3) Proved reserves for oil include volumes for NGLs (MBbls) of 183 MBbls, 146 MBbls and 101 MBbls attributable to the Underlying Properties, 80% of the Underlying Properties and the Net Profits Interest, respectively.
 
(4) The proved reserves for 80% of the Underlying Properties and the Net Profits Interest of 21,651 Mboe and 12,818 Mboe differ by 8,833 Mboe. Proceeds from the sale of the 8,833 Mboe will be used to cover 80% of the future production and development costs attributable to the Underlying Properties for the benefit of the trust.
 
(5) Future production costs for the Net Profits Interest consist solely of severance taxes and ad valorem taxes attributable to the trust.
 
(6) The present values of the future net revenues for the Underlying Properties and the Net Profits Interest were determined using a discount rate of 10% per annum. As of December 31, 2010, Enduro Sponsor was structured as a limited liability company. Accordingly, no provision for federal or state income taxes has been provided because taxable income was passed through to the members of Enduro Sponsor.
 
Average net production from the Underlying Properties for the year ended December 31, 2010 was approximately 5,847 Boe per day (or 4,678 Boe per day attributable to 80% of the Underlying Properties for the benefit of the trust), comprised of approximately 44% oil and 56% natural gas. For 2010, the oil revenues generated by the Underlying Properties was $70.0 million and natural gas revenues generated by the Underlying Properties was $33.8 million.
 
Enduro Sponsor’s interests in the Underlying Properties require Enduro Sponsor to bear its proportionate share of the costs of development and operation of such properties. As of December 31, 2010, Enduro Sponsor held average working interests of 19.52% and 26.16% and average net revenue interest of 16.11% and 20.00% in the Underlying Properties located in the Permian Basin and East Texas/North Louisiana regions, respectively. The Underlying Properties are also burdened by non-cost bearing interests owned by third parties consisting primarily of overriding royalty and royalty interests.
 
Unaudited Pro Forma Combined Financial and Operating Data of the Underlying Properties
 
The following table sets forth revenues, direct operating expenses and the excess of revenues over direct operating expenses relating to the Underlying Properties for the three months ended March 31, 2011 and 2010 and for the three years in the period ended December 31, 2010 derived from the unaudited pro forma combined statements of historical revenues and direct operating expenses of the Underlying Properties included elsewhere in this prospectus.
 
                                         
    Three Months Ended March 31,     Year Ended December 31,  
    2011     2010     2010     2009     2008  
    (In thousands)  
 
Revenues:
                                       
Oil
  $ 20,150     $ 17,354     $ 70,033     $ 55,309     $ 106,801  
Natural gas
    7,262       9,838       33,787       33,053       76,001  
                                         
Total revenues
  $ 27,412     $ 27,192     $ 103,820     $ 88,362     $ 182,802  
                                         
Direct operating expenses:
                                       
Lease operating
  $ 6,185     $ 6,206     $ 24,579     $ 25,822     $ 29,331  
Gathering and processing
    489       419       1,977       1,885       3,035  
Production and other taxes
    2,005       2,052       8,069       7,512       11,217  
                                         
Total direct operating expenses
  $ 8,679     $ 8,677     $ 34,625     $ 35,219     $ 43,583  
                                         
Excess of revenues over direct operating expenses
  $ 18,733     $ 18,515     $ 69,195     $ 53,143     $ 139,219  
                                         


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The following table provides oil and natural gas sales volumes, average sales prices, average costs per Boe and capital expenditures relating to the Underlying Properties for the three months ended March 31, 2011 and 2010 and for the three years in the period ended December 31, 2010. This operating data includes the effect of the Acquired Properties for all periods presented.
 
                                         
    Three Months Ended
       
    March 31,     Year Ended December 31,  
    2011     2010     2010     2009     2008  
    (Unaudited)  
 
Operating data:
                                       
Permian Basin
                                       
Sales volumes:
                                       
Oil (MBbls)
    226       233       921       985       1,051  
Natural gas (MMcf)
    490       494       2,195       2,386       2,419  
Total sales (MBoe)
    308       316       1,287       1,382       1,454  
Average sales prices:
                                       
Oil (per Bbl)
  $ 87.68     $ 72.62     $ 74.58     $ 54.44     $ 98.71  
Natural gas (per Mcf)
  $ 5.68     $ 6.49     $ 5.77     $ 4.41     $ 8.89  
Average costs per Boe:
                                       
Lease operating
  $ 16.03     $ 16.14     $ 15.62     $ 14.80     $ 16.94  
Gathering and processing
  $ 0.33     $ 0.36     $ 0.35     $ 0.30     $ 0.39  
Production and other taxes
  $ 5.71     $ 5.16     $ 5.20     $ 4.01     $ 6.16  
Capital expenditures (in thousands):
                                       
Property development costs
  $ 6,039     $ 292     $ 29,257     $ 1,606     $ 11,911  
                                         
East Texas/North Louisiana
                                       
Sales volumes:
                                       
Oil (MBbls)
    4       6       18       31       33  
Natural gas (MMcf)
    1,129       1,274       4,976       6,069       6,449  
Total sales (MBoe)
    192       218       847       1,043       1,108  
Average sales prices:
                                       
Oil (per Bbl)
  $ 83.75     $ 72.17     $ 74.72     $ 54.35     $ 92.64  
Natural gas (per Mcf)
  $ 3.97     $ 5.21     $ 4.24     $ 3.71     $ 8.45  
Average costs per Boe:
                                       
Lease operating
  $ 6.44     $ 5.12     $ 5.29     $ 5.14     $ 4.24  
Gathering and processing
  $ 2.01     $ 1.41     $ 1.80     $ 1.41     $ 2.23  
Production and other taxes
  $ 1.26     $ 1.95     $ 1.62     $ 1.88     $ 2.04  
Capital expenditures (in thousands):
                                       
Property development costs
  $ 6,066     $ 1,489     $ 7,779     $ 16,926     $ 53,660  
                                         
Total Underlying Properties
                                       
Sales volumes:
                                       
Oil (MBbls)
    230       239       939       1,016       1,084  
Natural gas (MMcf)
    1,619       1,768       7,171       8,455       8,868  
Total sales (MBoe)
    500       534       2,134       2,425       2,562  
Average sales prices:
                                       
Oil (per Bbl)
  $ 87.61     $ 72.61     $ 74.58     $ 54.44     $ 98.52  
Natural gas (per Mcf)
    4.49       5.56       4.71       3.91       8.57  
Average costs per Boe:
                                       
Lease operating
  $ 12.37     $ 11.62     $ 11.52     $ 10.65     $ 11.45  
Gathering and processing
    0.98       0.79       0.93       0.78       1.18  
Production and other taxes
    4.01       3.58       3.78       3.10       4.38  
Capital expenditures (in thousands):
                                       
Property development costs
  $ 12,105     $ 1,781     $ 37,036     $ 18,532     $ 65,571  


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Discussion and Analysis of Pro Forma Combined Historical Results of the Underlying Properties
 
Comparison of Pro Forma Combined Historical Results for the Three Months Ended March 31, 2011 and 2010
 
Excess of revenues over direct operating expenses for the Underlying Properties increased by $0.2 million to $18.7 million for the three months ended March 31, 2011 as a result of a $0.2 million increase in revenues.
 
Revenues.  Revenues from oil and natural gas sales increased $0.2 million between the periods. This increase in revenues was primarily the result of an increase in the average price received for crude oil sold from $72.61 per Bbl for the three months ended March 31, 2010 to $87.61 per Bbl for the three months ended March 31, 2011, partially offset by a 0.1 MBbl decrease in oil volumes sold.
 
Lease operating expenses.  Lease operating expenses remained relatively constant at $6.2 million for the three months ended March 31, 2011 and March 31, 2010.
 
Gathering and processing expenses.  Gathering and processing expenses increased by $0.1 million from $0.4 million for the quarter ended March 31, 2010 to $0.5 million for the quarter ended March 31, 2011.
 
Production and other taxes.  Production and other taxes decreased $0.1 million as a result of the decrease in oil and natural gas volumes sold on which production taxes are based.
 
Comparison of Pro Forma Combined Historical Results for the Years Ended December 31, 2010 and 2009
 
Excess of revenues over direct operating expenses for the Underlying Properties was $69.2 million for the year ended December 31, 2010, compared to $53.1 million for the year ended December 31, 2009. The increase was primarily a result of an increase in the average price received for the oil and natural gas sold. This was partially offset by a decrease in production.
 
Revenues.  Revenues from oil and natural gas sales increased $15.5 million between the periods. This increase in revenues was primarily the result of an increase in the average price received for crude oil sold from $54.44 per Bbl for the year ended December 31, 2009 to $74.58 per Bbl for the year ended December 31, 2010, partially offset by a 77 MBbl decrease in oil volumes sold. The increase in revenues was also the result of an increase in the average price received for natural gas sold from $3.91 per Mcf for the year ended December 31, 2009 to $4.71 per Mcf for the year ended December 31, 2010, partially offset by a 1,284 MMcf decrease in natural gas volumes sold.
 
Lease operating expenses.  Lease operating expenses decreased to $24.6 million for the year ended December 31, 2010 from $25.8 million for the year ended December 31, 2009, primarily due to a decrease in volumes partially offset by an $0.87 per Boe increase in lease operating expense rate.
 
Gathering and processing expenses.  Gathering and processing expenses remained essentially stable increasing by $0.1 million to $2.0 million for the year ended December 31, 2010.
 
Production and other taxes.  Production and other taxes increased $0.6 million as a result of the increase in revenues from oil and natural gas sales on which these taxes are based.
 
Comparison of Pro Forma Combined Historical Results for the Years Ended December 31, 2009 and 2008
 
The pro forma combined historical results for the year ended December 31, 2008 were derived from the audited statements of revenues and direct operating expenses of the Predecessor Underlying Properties, the Samson Permian Basin Assets and the ConocoPhillips Permian Basin Assets, in each case for the year ended December 31, 2008, which are included in this prospectus on pages F-5, F-14 and F-22, respectively.


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Excess of revenues over direct operating expenses for the Underlying Properties was $53.1 million for the year ended December 31, 2009, compared to $139.2 million for the year ended December 31, 2008. The decrease was primarily a result of a decrease in the average price received for the oil and natural gas sold.
 
Revenues.  Revenues from oil and natural gas sales decreased $94.4 million between these periods. This decrease in revenues was primarily the result of a decrease in the average price received for crude oil sold from $98.52 per Bbl for the year ended December 31, 2008 to $54.44 per Bbl for the year ended December 31, 2009, and a 68 MBbl decrease in oil volumes sold. The decrease in revenues was also the result of a decrease in the average price received for natural gas sold from $8.57 per Mcf for the year ended December 31, 2008 to $3.91 per Mcf for the year ended December 31, 2009, and a 413 MMcf decrease in natural gas volumes sold.
 
Lease operating expenses.  Lease operating expenses decreased from $29.3 million for the year ended December 31, 2008 to $25.8 million for the year ended December 31, 2009. This decrease was primarily a result of a decrease in volumes.
 
Gathering and processing expenses.  Gathering and processing expenses decreased $1.1 million from $3.0 million for the year ended December 31, 2008 to $1.9 million for the same period in 2009 due to lower volumes coupled with a lower processing fee per Mcf.
 
Production and other taxes.  Production and other taxes decreased $3.7 million as a result of the decreases in the price of crude oil and in revenues from oil and natural gas sales, on which these taxes are based.
 
Hedge Contracts
 
The revenues derived from the Underlying Properties depend substantially on prevailing oil prices and, to a lesser extent, natural gas prices. As a result, commodity prices also affect the amount of cash flow available for distribution to the trust unitholders. Lower prices may also reduce the amount of oil and natural gas that the Third Party Operators or Enduro Sponsor can economically produce. Enduro Sponsor has entered into hedge contracts to reduce the exposure of the revenues from oil and natural gas production from the Underlying Properties to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. However, these contracts limit the amount of cash available for distribution if prices increase above the fixed hedge price. The hedge contracts consist of commodity derivative contracts with unaffiliated third parties in order to mitigate the effects of falling commodity prices through 2013.
 
The following table sets forth the volumes of Enduro Sponsor’s natural gas commodity derivative contracts, the weighted average contractual prices per Mcf, and the weighted average NYMEX equivalent prices per Mcf as of June 30, 2011:
 
                                                 
    Put Contracts     Swap Contracts  
                Average
                Average
 
          Average
    NYMEX
          Average
    NYMEX
 
    Daily
    Contractual
    Equivalent
    Daily
    Contractual
    Equivalent
 
Period
  Volumes     Price     Price(1)     Volumes     Price     Price(1)  
    (Mcf)     ($/Mcf)     ($/Mcf)     (Mcf)     ($/Mcf)     ($/Mcf)  
 
July 2011 — December 2011
    14,000     $ 4.20     $ 4.46       10,000     $ 4.30     $ 4.52  
2012
    14,000     $ 4.90     $ 5.05       10,000     $ 4.57     $ 4.79  
2013
    12,000     $ 4.90     $ 5.17       8,000     $ 5.00     $ 5.20  
 
 
(1) Enduro Sponsor’s natural gas derivative contracts are comprised of contracts entered into at local basis points, such as Centerpoint and El Paso Permian, as well as NYMEX-based contracts. For presentation purposes and for comparability among the various contracts, the contract prices were converted to NYMEX equivalent prices using estimated basis differentials in the over-the-counter futures market.


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Of Enduro Sponsor’s natural gas put contracts shown above, for 2011, 2012, and 2013, approximately 64%, 64%, and 67%, respectively, of the hedged volumes relate to the Underlying Properties. For all periods shown above, 50% of Enduro Sponsor’s hedged volumes under swap contracts relate to the Underlying Properties.
 
The following table sets forth the volumes of Enduro Sponsor’s oil commodity derivative contracts and the weighted average NYMEX prices per Bbl as of June 30, 2011:
 
                                                                 
    Daily
    Average
          Average
    Average
    Average
    Daily
    Average
 
    Put
    Put
    Daily
    Sub-Floor
    Floor
    Cap
    Swap
    Swap
 
    Volumes
    Price
    Volumes
    Price
    Price
    Price
    Volumes
    Price
 
Period
  (Bbls)     ($/Bbl)     (Bbls)     ($/Bbl)     ($/Bbl)     ($/Bbl)     (Bbls)     ($/Bbl)  
 
July 2011 — December 2011
    500     $ 92.00       500     $ 67.50     $ 90.00     $ 110.00       530     $ 102.96  
2012
    500     $ 92.00       500     $ 67.50     $ 90.00     $ 110.00       520     $ 104.10  
2013
        $       500     $ 67.50     $ 90.00     $ 110.00       510     $ 102.97  
 
All the oil commodity derivative contracts shown above relate to the Underlying Properties.
 
The trust will not bear any hedge settlement costs paid by Enduro Sponsor, or be entitled to any hedge payments received by Enduro Sponsor, for periods on or prior to June 30, 2011.
 
The amounts received by Enduro Sponsor from the hedge contract counterparty upon settlement of the hedge contracts will reduce the operating expenses related to the Underlying Properties in calculating net profits. In addition, the aggregate amounts paid by Enduro Sponsor on settlement of the hedge contracts related to the Underlying Properties will reduce the amount of net profits paid to the trust. See “Computation of Net Profits — Net Profits Interest.”
 
Producing Acreage and Well Counts
 
For the following data, “gross” refers to the total number of wells or acres in which Enduro Sponsor owns a working interest and “net” refers to gross wells or acres multiplied by the percentage working interest owned by Enduro Sponsor. All of the acreage comprising the Underlying Properties is held by production. Although many of Enduro Sponsor’s wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas production. The Underlying Properties are interests in properties located in the Permian Basin of West Texas and New Mexico and in the East Texas/North Louisiana region. The following is a summary of the approximate acreage of the Underlying Properties at December 31, 2010.
 
                 
    Acres  
    Gross     Net  
 
Permian Basin
    278,612       30,350  
East Texas/North Louisiana
    15,440       4,113  
                 
Total
    294,052       34,463  
                 
 
The following is a summary of the producing wells on the Underlying Properties as of December 31, 2010:
 
                                 
    Oil     Natural Gas  
    Gross Wells(1)     Net Wells     Gross Wells(1)     Net Wells  
 
Permian Basin
    4,161       753.5       130       23.5  
East Texas/North Louisiana
                385       100.7  
                                 
Total
    4,161       753.5       515       124.2  
                                 
 
 
(1) Enduro Sponsor’s total wells include 34 operated wells and 4,642 non-operated wells. At December 31, 2010, 64 of Enduro Sponsor’s wells had multiple completions.


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The following is a summary of the number of development and exploratory wells drilled on the Underlying Properties during the last three years.
 
                                                 
    Year Ended December 31,  
    2010     2009     2008  
    Gross     Net     Gross     Net     Gross     Net  
 
Permian Basin
                                               
Development Wells:
                                               
Productive
    55       10.9       38       1.3       79       5.3  
Dry holes
                                   
                                                 
      55       10.9       38       1.3       79       5.3  
                                                 
Exploratory Wells:
                                               
Productive
                                   
Dry holes
                                   
                                                 
                                     
                                                 
Total:
                                               
Productive
    55       10.9       38       1.3       79       5.3  
Dry holes
                                   
                                                 
      55       10.9       38       1.3       79       5.3  
                                                 
 
                                                 
    Year Ended December 31,  
    2010     2009     2008  
    Gross     Net     Gross     Net     Gross     Net  
 
East Texas/North Louisiana
                                               
Development Wells:
                                               
Productive
    3       0.3       4       0.7       57       17.6  
Dry holes
                                   
                                                 
      3       0.3       4       0.7       57       17.6  
                                                 
Exploratory Wells:
                                               
Productive
    8       0.7       4       0.7       14       4.3  
Dry holes
                3       0.5              
                                                 
      8       0.7       7       1.2       14       4.3  
                                                 
Total:
                                               
Productive
    11       1       8       1.3       71       21.9  
Dry holes
                3       0.5              
                                                 
      11       1       11       1.8       71       21.9  
                                                 


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Operating Areas
 
The following table summarizes the estimated proved reserves by operating area attributable to the Underlying Properties according to the reserve reports and the corresponding pre-tax PV-10 value as of December 31, 2010.
 
                                                     
        Proved Reserves(1)  
                                      % of
 
              Natural
          % of
    PV-10
    Total
 
    Producing
  Oil
    Gas
    Total
    Total
    Value(2)
    PV-10
 
Operating Area
  Formation   (MBbls)     (MMcf)     (MBoe)     Reserves     (In thousands)     Value  
 
Permian Basin
                                                   
North Monument
                                                   
Grayburg Unit
  Grayburg/San Andres     2,028       1,471       2,273       15 %   $ 42,989       15 %
North Central Levelland Unit
  San Andres     2,330       265       2,374       14 %   $ 39,208       14 %
North Cowden Unit
  Grayburg/San Andres     2,403       993       2,569       16 %   $ 32,563       12 %
Yates Field Unit
  Grayburg/San Andres     633             633       4 %   $ 18,052       6 %
Other
  Various     5,347       18,752       8,472       51 %   $ 147,163       53 %
                                                     
Permian Basin Total
        12,741       21,481       16,321       100 %   $ 279,975       100 %
East Texas/North Louisiana
                                                   
Elm Grove Field
  Cotton Valley, Hosston, Travis Peak, Haynesville Shale     2       55,442       9,238       86 %   $ 54,591       79 %
Kingston Field
  Travis Peak, Haynesville Shale           6,570       1,100       10 %   $ 10,027       14 %
Stockman Field
  Travis Peak     23       2,294       405       4 %   $ 4,939       7 %
                                                     
East Texas/North Louisiana
                                                   
Total
        25       64,306       10,743       100 %   $ 69,557       100 %
                                                     
Total
        12,766       85,787       27,064       100 %   $ 349,532       100 %
                                                     
 
 
(1) In accordance with the rules and regulations promulgated by the SEC, the proved reserves presented above were determined using the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from January 1, 2010 through December 1, 2010, without giving effect to any hedge transactions, and were held constant for the life of the properties. This yielded a price for oil of $79.43 per Bbl and a price for natural gas of $4.37 per MMBtu.
 
(2) PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted using an annual discount rate of 10%, calculated without deducting future income taxes and future abandonment costs. Standardized measure of discounted future net cash flows is calculated the same as PV-10 except that it deducts future income taxes and future abandonment costs. Because the trust bears no federal tax expense and taxable income is passed through to the unitholders of the trust, no provision for federal or state income taxes is included in the summary reserve reports. PV-10 may not be considered a GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. The pre-tax PV-10 value and the standardized measure of discounted future net cash flows do not purport to present the fair value of the oil and natural gas reserves attributable to Underlying Properties.
 
Substantially all of the Underlying Properties are located in mature oil fields that are characterized by long production histories and additional development opportunities, which may help to diminish natural declines in production from the Underlying Properties. Based on the reserve reports, approximately 47% of the future production from the Underlying Properties is expected to be oil and approximately 53% is expected to be natural gas.


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Oil Recovery Overview
 
When an oil field is first produced, the oil typically is recovered as a result of natural pressure within the producing formation, often assisted by pumps of various types. The only natural force present to move the crude oil to the wellbore is the pressure differential between the higher pressure in the formation and the lower pressure in the wellbore. At the same time, there are many factors that act to impede the flow of crude oil, depending on the nature of the formation and fluid properties, such as pressure, permeability, viscosity and water saturation. This stage of production, referred to as “primary production,” recovers only a small fraction of the crude oil originally in place in a producing formation.
 
Many, but not all, oil fields are amenable to assistance from a waterflood, a form of “secondary recovery,” which is used to maintain reservoir pressure and to help sweep oil to the wellbore. In a waterflood, certain wells are used to inject water into the reservoir while other wells are used to produce the fluid. As the waterflood matures, the fluid produced contains increasing amounts of water and decreasing amounts of oil. Surface equipment is used to separate the oil from the water, with the oil going to pipelines or holding tanks for sale and the water being recycled to the injection facilities. Primary recovery followed by secondary recovery usually produces between 20% and 40% of the crude oil originally in place in a producing formation.
 
A third stage of oil recovery is called “tertiary recovery” or “enhanced oil recovery” (“EOR”). In addition to maintaining reservoir pressure, this type of recovery seeks to alter the properties of the oil in ways that facilitate production. A commonly utilized method of tertiary recovery involves the use of a CO2 flood, where CO2 is liquefied under high pressure and injected into the reservoir. The CO2 then swells the oil in a way that increases the mobilization of by-passed oil while also reducing the oil’s viscosity. The lighter oil fractions vaporize into the CO2 while the CO2 also condenses into the reservoir’s oil. In this manner, the two fluids become miscible, mixing to form a homogeneous fluid that is mobile and has lower viscosity and lower interfacial tension. The implementation of a CO2 flood can result in increased production growth and recovery over and above that which is produced through primary and secondary recovery methods.
 
Permian Basin Region
 
The Permian Basin is one of the largest and most prolific oil and natural gas producing basins in the United States. The Permian Basin extends over 100,000 square miles in West Texas and southeast New Mexico and has produced over 24 billion Bbls of oil since its discovery in 1921. The Permian Basin is characterized by oil and natural gas fields with long production histories and multiple producing formations. The Underlying Properties in the Permian Basin contain 278,612 gross (30,350 net) acres in Texas and New Mexico. Approximately, 63% of the oil produced in the Underlying Properties in the Permian Basin comes from waterflooding and CO2 flooding.
 
Four of the largest fields in the Permian Basin region of the Underlying Properties are the following (measured by PV-10 value):
 
  •      The largest field in the Permian Basin region is the Apache operated North Monument Grayburg Unit discovered in 1929. This unit produces 293 Boe per day net to Enduro Sponsor’s interest from the Grayburg and San Andres formations of which 90% is oil. Proved reserves attributable to the Underlying Properties in the North Monument Grayburg Unit are 2.3 MMBoe as of December 31, 2010.
 
  •      The second largest field in the Permian Basin region is the Apache operated North Central Levelland Unit discovered in 1937. This unit produces from the San Andres formation at a depth of approximately 4,900 feet. The North Central Levelland Unit is a waterflood property and produces 397 Boe per day net to Enduro Sponsor’s interest of which 98% is oil. Proved reserves attributable to the Underlying Properties in the North Central Levelland Unit are 2.4 MMBoe as of December 31, 2010.


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  •      The third largest field in the Permian Basin region is the North Cowden Unit discovered in 1930. The North Cowden Unit is undergoing both waterflood and CO2 recovery processes. The field produces 455 Boe per day net to Enduro Sponsor’s interest of which 94% is oil. This production is produced from the Grayburg formation at a depth of 4,500 feet. Proved reserves attributable to the Underlying Properties in the North Cowden field are 2.6 MMBoe as of December 31, 2010. The operator of the North Cowden field is Occidental, the largest oil and gas operator in the Permian Basin.
 
  •      The fourth largest field in the Permian Basin region is the Yates Field discovered in 1926. Kinder Morgan is the operator of the field and is producing oil through the implementation of both waterflood and CO2 processes. The Yates Field produces 159 Boe per day net to Enduro Sponsor’s interest of which 100% is oil. Proved reserves attributable to the Underlying Properties in the Yates Field are 633 MBoe as of December 31, 2010.
 
The following table sets forth the recovery method and certain additional information about some of the fields in the Permian Basin region:
 
                                                 
                    Original
       
                    Oil in
  Cumulative
   
        Recovery
  Working
  Net Revenue
  Place
  Production
  PV-10
Unit Name
  Operator   Method   Interest (%)   Interest (%)   (MMBO)(1)   (MMBO)   (Millions)
 
North Monument Grayburg Unit
  Apache   Waterflood     11.2       9.9       580 (2)     152     $ 43  
North Central Levelland Unit
  Apache   Waterflood     30.9       23.3       142 (3)     56     $ 39  
North Cowden Unit
  Occidental   Waterflood/CO2     8.5       7.6       1,266 (4)     270     $ 33  
Yates Field Unit
  Kinder Morgan   Waterflood/CO2     0.8       0.7       4,000 (5)     1,235     $ 18  
South Foster Unit
  Occidental   Waterflood     12.7       11.1       163 (6)     45     $ 10  
Eunice Monument South Unit A
  XTO   Waterflood     9.4       8.1       672 (7)     110     $ 7  
Jo-Mill Unit
  Chevron   Waterflood     1.2       1.1       326 (8)     76     $ 4  
West Spraberry Unit
  Chevron   Waterflood     22.7       19.7       60 (9)     14     $ 4  
Spraberry Driver Unit
  Pioneer   Waterflood     1.0       0.8       600 (10)     88     $ 3  
Eunice Monument South Unit B
  XTO   Waterflood     14.1       11.7       136 (11)     22     $ 3  
Corrigan Cowden Unit
  Occidental   Waterflood     12.2       10.7       44 (12)     18     $ 2  
 
 
(1) Original oil in place is not an indication of the quantity of oil that is likely to be produced, but rather an indication of the estimated size of a reservoir.
 
(2) New Mexico Oil Conservation Division Case No: 10253 Navigational Message Generation Unit Application Hearing dated April 4, 1991 filed by Amerada Hess Corporation as operator.
 
(3) Texas Railroad Commission April 20, 2001 Form H-1 filing by Mobil Producing TX & NM Inc. as operator.
 
(4) Texas Railroad Commission January 16, 2001 Form H-1 filing by Occidental Permian Ltd as operator.
 
(5) Texas Railroad Commission December 30, 1999 Form H-1 filing by Marathon Oil Company as operator.
 
(6) Texas Railroad Commission September 11, 2001 Form H-1 filing by Occidental Permian Ltd as operator.
 
(7) New Mexico Oil Conservation Division April, 1983 Technical Committee Report for Unitization filing by the Eunice Monument South Unit Working Interest owners.
 
(8) Texas Railroad Commission September 18, 1968 Form H-1 filing by Texaco Inc. as operator.
 
(9) Texas Railroad Commission April 21, 2000 Form H-1 filing by Texaco E&P Inc. as operator.
 
(10) Texas Railroad Commission February 24, 1993 Form H-1 filing by Texaco E&P Inc. as operator.
 
(11) New Mexico Oil Conservation Division April, 1983 Technical Committee Report for Unitization filing by the Eunice Monument South Unit Working Interest owners.


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(12) Texas Railroad Commission June 4, 1990 Form H-1 filing by ARCO Oil and Gas Company as operator.
 
Enduro Sponsor owns a working interest in the above fields. Each field was identified in a 2006 study by the United States Department of Energy as having a favorable reservoir for potential CO2 upside recovery based on reservoir depth, oil gravity, reservoir pressure, reservoir temperature and oil composition. Enduro Sponsor will not be able to influence development activities in the non-operated fields, and no assurance can be given that CO2 flooding will commence at any time in the future or will continue to be used on any of the above fields.
 
East Texas/North Louisiana Region
 
Historically, much of the East Texas/North Louisiana region was directed at the James Lime, Pettet, Travis Peak and Cotton Valley formations. Beginning in 2008, companies in the region began to focus on the development of the Haynesville Shale utilizing horizontal drilling technology and multi-stage hydraulic fracturing well completion techniques. According to the Energy Information Administration, in 2011 the Haynesville Shale became the leading shale play in the United States by production volume. In 2010, operators began experimenting with down-spacing to 80-acre well spacing in parts of the Haynesville Shale from 160-acre well spacing, with a goal of increased overall gas recovery from the shale. Enduro Sponsor believes that Haynesville Shale wells will produce on average 87% of their reserves in the first 20 years. Operators have also begun to focus on the efficiencies, such as drilling multiple wells from a single condensed pad location, reducing drilling times, combining fracture stimulation activities and designing facilities to be shared, in an effort to streamline operations and cut costs. Current activity on Enduro Sponsor’s acreage is focused on the horizontal development of the Haynesville Shale and Cotton Valley sands. In addition, operators in the region are beginning to test additional formations in the area such as the Bossier, Cotton Valley Lime and Smackover formations.
 
The Underlying Properties contain interests in 15,440 gross (4,113 net) acres in this region across three fields: the Elm Grove Field, operated by Petrohawk, the Kingston Field, operated by EXCO Resources, Inc., and the Stockman Field, operated by Enduro Sponsor. In the Kingston Field, EXCO Resources is drilling wells on 80-acre well spacing. Based on continued 80-acre well spacing, Enduro Sponsor believes the Underlying Properties may support additional Haynesville Shale wells. The proved reserves associated with the Underlying Properties in the East Texas/North Louisiana region do not include reserves attributable to 80-acre well spacing nor are there any reserves from the Bossier, Cotton Valley Lime or Smackover formations. However, the Underlying Properties include the economic rights to production from these formations on Enduro Sponsor’s acreage position in the event that production is generated from them. Enduro Sponsor will not be able to influence development activities in the non-operated fields, and no assurance can be given that such down spacing will continue or that the referenced additional formations will be produced.
 
Near Term Development Activities
 
Payment of Operating and Development Expenses
 
The Third Party Operators and, with respect to the Stockman Field, Enduro Sponsor, are entitled to make all determinations related to development and operating expenses with respect to the Underlying Properties, and there are no limitations on the amount of development or operating expenses that the Third Party Operators and Enduro Sponsor may incur with respect to the Underlying Properties. The trust is not directly obligated to pay any portion of any operating and development expenses made with respect to the Underlying Properties; however, operating and development expenses made by Enduro Sponsor with respect to the Underlying Properties will be included among the costs that will be deducted from the gross profits in calculating cash distributions attributable to the Net Profits Interest. As a result, the trust will indirectly bear an 80% share of any operating and development expenses made with respect to the Underlying Properties. Accordingly, higher or lower


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operating and development expenses will, in general, directly decrease or increase, respectively, the cash received by the trust. Please read “Computation of Net Profits — Net Profits Interest.”
 
2011 Capital Budget
 
Historical Activity.  Enduro Sponsor has estimated the development of the proved undeveloped reserves attributable to the Underlying Properties based on historical activity and known current development plans of the Third Party Operators. In 2008, 2009 and 2010, 150 gross (27.2 net) wells, 49 gross (3.1 net) wells, and 66 gross (11.9 net) wells, respectively, were drilled on the Underlying Properties. In 2011, 47 gross (15.3 net) wells have been drilled or proposed and approved for drilling by Enduro Sponsor as of June 2011. Enduro Sponsor has a good working relationship with its Third Party Operators and has discussed future drilling and development plans with them.
 
East Texas/North Louisiana Region.  For 2011, Enduro Sponsor has a capital budget of $25 million for the East Texas/North Louisiana region. Enduro Sponsor has spent $5 million of this on proved undeveloped projects and $9 million on non-proven probable projects and has dedicated $11 million to approved future projects not represented in the proved reserves. Enduro Sponsor has agreed to pay up to $9.1 million of development expenses in 2011 that occur after May 1, 2011 with respect to specified projects, which is included in Enduro Sponsor’s $25 million capital budget for 2011.
 
In 2011, much of the drilling activity in the East Texas/North Louisiana region has been associated with the Haynesville Shale formation, with 26 gross (2.5 net) wells having been drilled, spud, or proposed and approved. In the East Texas/North Louisiana region, Enduro Sponsor has been notified by the largest Third Party Operators of the Underlying Properties, EXCO Resources Inc. and Petrohawk, of plans to continue development in the Haynesville Shale and Lower Cotton Valley in the near term. EXCO is currently proposing 6 to 8 wells per section in the Haynesville Shale and plans to drill the wells at one time. These wells are being prepared on 80-acre spacing. The Haynesville Shale development is a fast moving immature play with much of the drilling considered to be new and extensional. As a result, the activity does not conform to the standard for proved reserves and does not appear in the reserve report relating to the Underlying Properties. Based on the level of activity in these areas and the current natural gas price environment, Enduro Sponsor believes that it is able to reasonably estimate the level of drilling activity in the near future. Enduro Sponsor expects the Third Party Operators to drill 4 proved undeveloped wells in 2011.
 
In the East Texas/North Louisiana region, of the 26 wells proposed to be drilled during 2011, a total of 5 wells have been drilled to date, but only 4 wells were scheduled as proved undeveloped locations in the reserve report relating to the Underlying Properties. There have been an additional 21 wells spud or proposed and approved by Enduro Sponsor in 2011 that are not represented in the reserve report because they would not be classified as proved locations but would rather be classified as probable locations based on the information available on December 31, 2010. These additional 21 wells would not be classified as proved because of one or more of the following reasons: (1) the drilling locations are more than one or two locations away from a producing well, (2) the drilling is occurring on smaller spacing than has historically occurred in the relevant field to be considered proven or (3) the wells are being drilled simultaneously in clusters of 6 or 8 wells where evidence of individual well commerciality cannot be determined. Enduro Sponsor has budgeted for this level of activity, which may have a positive impact on the proved reserves and production volumes in the future.
 
Permian Basin Region.  For 2011, Enduro Sponsor has a capital budget of $12 million for the Permian Basin region, of which $4 million has been spent on proved undeveloped projects and $5.5 million has been dedicated to approved future projects not represented in the proved reserves. The remaining $2.5 million has been budgeted for non-proven wells and unknown projects.
 
In the Permian Basin region, 8 gross (4 net) wells are in the process of being drilled in the Lost Tank field operated by Occidental Petroleum in 2011. An additional 12 gross (6 net) wells have been spud or proposed and approved in 2011 in the Lost Tank field. Because these 12 wells are more than


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one location away from a producing well they are not classified as proved locations and are therefore not in the reserve report. Occidental Petroleum has stated that they will not repeat this level of activity in the Lost Tank field after 2011. For 2011, all 8 of the proved undeveloped locations in the Lost Tank field in the reserve report have been drilled. Enduro Sponsor has not scheduled any additional proved undeveloped projects for the Permian Basin region in the reserve report after 2011.
 
2012 Capital Budget
 
Enduro Sponsor’s capital budget for the Underlying Properties in 2012 is estimated to be $19.6 million, of which $17.8 million is expected to be invested in the East Texas/North Louisiana region and $1.8 million is expected to be invested in the Permian Basin. These projects could maintain or increase future distributions to the trust unitholders.
 
In the East Texas/North Louisiana region, Enduro Sponsor’s capital budget is expected to be $17.8 million in 2012. Investments in this region will mainly flow into Haynesville Shale drilling projects in Caddo and De Soto Parishes in Louisiana. Enduro Sponsor believes its acreage in the Haynesville Shale area has significant upside potential. A majority of the 640 acre sections owned by Enduro Sponsor have only one producing well, which leaves 7 additional locations per section (assuming 80-acre spacing) to drive growth in this area for years to come.
 
In the Permian Basin, Enduro Sponsor’s capital budget is expected to be $1.8 million in 2012, including the North Cowden CO2 projects. Past projects have typically targeted the Wolfcamp, Wolfberry, Cherry Canyon and San Andres zones. Enduro Sponsor also owns an interest in other prospective CO2 units in the Permian Basin, with neighboring units being successfully flooded or expanded into units owned by Enduro Sponsor. The operators of these producing units have extensive experience in implementing CO2 floods, which increase production.
 
Other
 
Any additional incremental revenue received by Enduro Sponsor from additional production resulting from future capital expenditures could have the effect of increasing future distributions to the trust unitholders. No assurance can be given, however, that any development well will produce in commercial quantities or that the characteristics of any development well will match the characteristics of the Third Party Operators’ or Enduro Sponsor’s existing wells or historical drilling success rate.
 
Reserve Reports
 
Technologies.  The reserve reports were prepared using production performance decline curve analyses to determine the reserves of the Underlying Properties in Texas, Louisiana and New Mexico. After estimating the reserves of each proved developed property, it was determined that a reasonable level of certainty exists with respect to the reserves which can be expected from any individual undeveloped well in the field. The consistency of reserves attributable to the proved developed wells in Texas, Louisiana and New Mexico, which cover a wide area, further supports proved undeveloped classification.
 
The proved undeveloped locations in the Underlying Properties are direct offsets of other producing wells. Data from both Enduro Sponsor and offset operators with which Enduro Sponsor has exchanged technical data demonstrate a consistency in this resource play over an area much larger than the Underlying Properties. In addition, information from other producing wells has also been used to analyze reservoir properties such as porosity, thickness and stratigraphic conformity.
 
Internal controls.  Cawley Gillespie, the independent petroleum engineering consultant, estimated all of the proved reserve information for the Underlying Properties in this registration statement in accordance with appropriate engineering, geologic and evaluation principles and techniques that are in accordance with practices generally accepted in the petroleum industry, and definitions and guidelines established by the SEC. These reserves estimation methods and techniques are widely taught in university


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petroleum curricula and throughout the industry’s ongoing training programs. Although these engineering, geologic and evaluation principles and techniques are based upon established scientific concepts, the application of such principles and techniques involves extensive judgment and is subject to changes in existing knowledge and technology, economic conditions and applicable statutory and regulatory provisions. These same industry-wide applied techniques are used in determining estimated reserve quantities. The technical person primarily responsible for overseeing preparation of the reserves estimates and the third party reserve reports is John W. Arms, Enduro Sponsor’s Executive Vice President and Chief Operating Officer. Mr. Arms received a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines in 1991. Prior to co-founding Enduro Sponsor, Mr. Arms was Senior Vice President of Acquisitions for EAC. Mr. Arms has over 20 years of experience working in various capacities in the energy industry, including acquisition analysis, reserve estimation, reservoir engineering and operations engineering. Mr. Arms consults regularly with Cawley Gillespie during the reserve estimation process to review properties, assumptions and relevant data. Additionally, Enduro Sponsor’s senior management has reviewed and approved all Cawley Gillespie summary reserve reports contained in this prospectus.
 
The independent petroleum engineer’s report as to the proved oil and natural gas reserves as of December 31, 2010 were prepared by Cawley Gillespie. Cawley Gillespie, whose firm registration number is F-693, was founded in 1961 and is a leader in the evaluation of oil and gas properties. The technical person at Cawley Gillespie primarily responsible for overseeing the reserve estimate with respect to Enduro Sponsor, the Underlying Properties and the Net Profits Interest attributable to the trust is Robert D. Ravnaas. Mr. Ravnaas has been a petroleum consultant for Cawley Gillespie since 1983, and became Executive Vice President in 1999. He is a registered professional engineer in the State of Texas (license no. 61304) and a graduate of the University of Texas with an M.S. in Petroleum Engineering. In addition, Mr. Ravnaas received a B.Sc. with special honors in Chemical Engineering from the University of Colorado.
 
Cawley Gillespie estimated oil and natural gas reserves attributable to Enduro Sponsor, the Underlying Properties and the Net Profits Interest as of December 31, 2010. Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the original estimates.
 
The discounted estimated future net revenues presented below were prepared using the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from January 1, 2010 through December 1, 2010, without giving effect to any hedge transactions, and were held constant for the life of the properties. This yielded a price for oil of $79.43 per barrel and a price for natural gas of $4.37 per MMBtu. Oil equivalents in the table are the sum of the Bbls of oil and the Boe of the stated Mcfs of natural gas, calculated on the basis that six Mcfs of natural gas is the energy equivalent of one Bbl of oil. The estimated future net revenues attributable to the Net Profits Interest as of December 31, 2010 are net of the trust’s proportionate share of all estimated costs deducted from revenue pursuant to the terms of the conveyance creating the Net Profits Interest. Because oil and natural gas prices are influenced by many factors, use of the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from January 1, 2010 through December 1, 2010, as required by the SEC, may not be the most accurate basis for estimating future revenues of reserve data. Future net cash flows are discounted at an annual rate of 10%. There is no provision for federal income taxes with respect to the future net cash flows attributable to the Underlying Properties or the Net Profits Interest because future net revenues are not subject to taxation at the Enduro Sponsor or trust level.


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Proved reserves of Underlying Properties.  The following table sets forth, as of December 31, 2010, certain estimated proved reserves, estimated future net revenues and the discounted present value thereof attributable to the Underlying Properties, 80% of the Underlying Properties and the Net Profits Interest, in each case derived from the reserve reports.
 
                         
          80% of the
       
    Underlying
    Underlying
    Net Profit
 
    Properties(1)     Properties(2)     Interests  
    (In thousands)  
 
Proved Reserves
                       
Oil (MBbls)(3)
    12,766       10,213       5,642  
Natural Gas (MMcf)
    85,787       68,630       43,058  
Oil Equivalents (Mboe)(4)
    27,064       21,651       12,818  
Future Net Revenue
  $ 1,344,718     $ 1,075,774     $ 616,091  
Future Production Cost
  $ 578,014     $ 462,411     $ 48,895 (5)
Future Development Cost
  $ 57,674     $ 46,139     $  
                         
Future Net Income
  $ 709,030     $ 567,196     $ 567,196  
Present Value at 10% Discount Rate(6)
  $ 349,532     $ 279,688     $ 279,688  
Standardized Measure of Discounted Future Net Cash Flows
  $ 349,532     $ 279,688     $ 279,688  
 
 
(1) Reserve volumes and estimated future net revenues for the Underlying Properties reflect volumes and revenues attributable to Enduro Sponsor’s net interests in the properties comprising the Underlying Properties.
 
(2) Reflects 80% of the proved reserves and future net revenues, production and development costs, net income and present value attributable to the Underlying Properties expected to be produced based on the reserve report.
 
(3) Proved reserves for oil include volumes for NGLs (MBbls) of 183 MBbls, 146 MBbls and 101 MBbls attributable to the Underlying Properties, 80% of the Underlying Properties and the Net Profits Interest, respectively.
 
(4) The proved reserves for 80% of the Underlying Properties and the Net Profits Interest of 21,651 Mboe and 12,818 Mboe differ by 8,833 Mboe. Proceeds from the sale of the 8,833 Mboe will be used to cover 80% of the future production and development costs attributable to the Underlying Properties for the benefit of the trust.
 
(5) Future production costs for the Net Profits Interest consist solely of severance taxes and ad valorem taxes attributable to the trust.
 
(6) The present values of the future net revenues for the Underlying Properties and the Net Profits Interest were determined using a discount rate of 10% per annum. As of December 31, 2010, Enduro Sponsor was structured as a limited liability company. Accordingly, no provision for federal or state income taxes has been provided because taxable income was passed through to the members of Enduro Sponsor.
 
As proved reserves are evaluated using only direct costs such as production costs, production taxes, work-over, gathering and processing, transportation and drilling costs, if applicable, and other costs such as general and administrative, depreciation, depletion and amortization, interest and derivative losses are not included, the attribution of proved reserves is not necessarily a sign of future overall corporate profitability.


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Changes in Estimated Proved Reserves
 
The following table summarizes the changes in estimated proved reserves of the Underlying Properties for the periods indicated. The data is presented assuming Enduro Sponsor owned all the Underlying Properties as of December 31, 2007.
 
                         
                Oil
 
    Oil
    Natural Gas
    Equivalents
 
    (MBbls)     (MMcf)     (MBoe)  
 
Proved Reserves:
                       
Balance, January 1, 2008
    16,177       67,009       27,345  
Revisions of prior estimates(1)
    (4,374 )     23,731       (419 )
Production
    (1,084 )     (8,868 )     (2,562 )
                         
Balance, December 31, 2008
    10,719       81,872       24,364  
Revisions of prior estimates(1)
    2,466       2,705       2,917  
Production
    (1,016 )     (8,455 )     (2,425 )
                         
Balance, December 31, 2009
    12,169       76,122       24,856  
Revisions of prior estimates(1)
    1,536       16,836       4,342  
Production
    (939 )     (7,171 )     (2,134 )
                         
Balance, December 31, 2010
    12,766       85,787       27,064  
Proved Developed Reserves:
                       
Balance, December 31, 2008
    10,674       67,164       21,868  
Balance, December 31, 2009
    12,124       57,010       21,626  
Balance, December 31, 2010
    12,387       51,293       20,935  
Proved Undeveloped Reserves:
                       
Balance, December 31, 2008
    45       14,708       2,496  
Balance, December 31, 2009
    45       19,112       3,230  
Balance, December 31, 2010
    379       34,494       6,129  
 
 
(1) The Underlying Properties include a portion of the assets in East Texas and North Louisiana acquired by Enduro Sponsor from Denbury in December 2010, and all of the assets in the Permian Basin of New Mexico and West Texas acquired by Enduro Sponsor from Samson and ConocoPhillips in January 2011 and February 2011, respectively. Because Enduro Sponsor did not own the Underlying Properties prior to December 31, 2009, it does not have a detailed reserve reconciliation for the Underlying Properties for that period. Instead, Enduro Sponsor has used reserve information as derived from EAC’s 2008 and 2009 reserve reports, as well as its own reserve report for 2010, and rolled back the data from December 31, 2010 to December 31, 2009 and subsequently to December 31, 2008 for the ConocoPhillips and the Samson acquisitions.
 
During 2008, there were 150 wells drilled on the Underlying Properties. In the East Texas/North Louisiana region, there were 71 natural gas wells drilled. In the Permian Basin region, 79 vertical oil and natural gas wells were drilled in various fields and formations. The level and success of natural gas well drilling in the Cotton Valley and Hosston formations in East Texas/North Louisiana had a significant impact on the positive revision for natural gas reserves in 2008. There were no Haynesville Shale wells drilled in 2008.
 
During 2009, there were 49 wells drilled on the Underlying Properties. In the East Texas/North Louisiana region, there were eight natural gas wells drilled with four of these wells being drilled to the Haynesville Shale. In the Permian Basin region, 38 vertical oil and natural gas wells were drilled in various fields and formations. As a result of the drop in the level of the vertical well drilling activity in East Texas/North Louisiana, natural gas reserve revisions were less in 2009.


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During 2010, there were 66 wells drilled on the Underlying Properties. In the East Texas/North Louisiana region, there were 11 natural gas wells drilled. In the Permian Basin region, there were 55 oil and natural gas wells drilled vertically. The natural gas reserve revisions were greater than in 2008 and 2009 due to 11 horizontal wells being drilled in the Haynesville Shale in the East Texas/North Louisiana region in 2010.
 
The combination of a changing price environment together with successful drilling and growth in the Haynesville Shale has caused these fluctuations.
 
Reserve Estimates
 
Enduro Sponsor has not filed reserve estimates covering the Underlying Properties with any other federal authority or agency.
 
Changes in Proved Undeveloped Reserves
 
Permian Basin Region
 
In the Permian Basin region, ConocoPhillips received notice in October 2010 of an intent to drill in the Lost Tank field in New Mexico. After significant preparations were made by the operator to drill the wells, Enduro Sponsor recognized eight proved undeveloped well locations in the Lost Tank field in the 2010 reserve report, which represented 595 MBoe of reserves.
 
In the Permian Basin region, all eight proved undeveloped well locations in the 2010 reserve report relating to the Underlying Properties have been or are in the process of being drilled in 2011. This drilling activity will result in the movement of 595 MBoe of reserves from proved undeveloped in 2010 to proved developed in 2011 at a development cost of $4 million. Another 12 wells have been spud in 2011. These 12 wells are not included in the proved undeveloped category in future years in the Permian Basin region.
 
East Texas/North Louisiana Region
 
On Enduro Sponsor’s acreage, in 2008, there were 71 gross (21.9 net) wells drilled in the area characterized mainly by vertical Hosston, Cotton Valley and Travis Peak infill development drilling. There were no horizontal Haynesville Shale wells drilled in 2008 on the Underlying Properties. However, based in part on the success of drilling offset to Enduro Sponsor’s acreage, Third Party Operators drilled 8 gross (1.3 net) wells, 4 of which were drilled horizontally to the Haynesville Shale formation in 2009. In 2010, the drilling pace increased with 11 gross (1.0 net) horizontal wells to the Haynesville Shale formation at a capital cost of $9.5 million. As a result of the drilling activity in 2009 and 2010 and the positive results from that activity, Enduro Sponsor added 14 proved undeveloped well locations in the Haynesville Shale on its acreage in the 2010 reserve report relating to the Underlying Properties, which contributed significantly to the increase in Enduro Sponsor’s proved undeveloped reserves from 2008 to 2010.
 
Since December 31, 2010, progress has been made to develop proved undeveloped reserves. In the East Texas/North Louisiana region, two of the four wells scheduled for 2011 have been drilled in the Haynesville Shale, which will move 144 MBoe of proved undeveloped reserves in 2010 at a capital cost of $1.6 million to the proved developed category in 2011, representing 46% of the proved undeveloped reserves for 2011 in the Kingston and Elm Grove fields. Another 16 wells have been spud or have drilling in progress and eight more wells have been proposed and approved by Enduro Sponsor for the Haynesville Shale in 2011. Of these 26 wells, three wells represent 399 MBoe of reserves (87% of the proved undeveloped reserves for 2011) and are included in the proved undeveloped category for future years in the East Texas/North Louisiana region.


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Development of Proved Undeveloped Reserves
 
All proved undeveloped locations are scheduled to be spud within the next five years. Enduro Sponsor does not recognize proved undeveloped reserves beyond five years.
 
Sale and Abandonment of Underlying Properties
 
The operators of the Underlying Properties or any transferee will have the right to abandon its interest in any well or property if it reasonably believes a well or property ceases to produce or is not capable of producing in commercially paying quantities. Upon termination of the lease, the portion of the Net Profits Interest relating to the abandoned property will be extinguished.
 
Enduro Sponsor generally may sell all or a portion of its interests in the Underlying Properties, subject to and burdened by the Net Profits Interest, without the consent of the trust unitholders. In addition, Enduro Sponsor may, without the consent of the trust unitholders, require the trust to release the Net Profits Interest associated with any lease that accounts for less than or equal to 0.25% of the total production from the Underlying Properties in the prior 12 months and provided that the Net Profits Interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the trust of $500,000. These releases will be made only in connection with a sale by Enduro Sponsor to a non-affiliate of the relevant Underlying Properties and are conditioned upon the trust receiving an amount equal to the fair value to the trust of such Net Profits Interest. Enduro Sponsor has not identified for sale any of the Underlying Properties.
 
Hydraulic Fracturing
 
As of December 31, 2010, all of the total proved reserves associated with the Underlying Properties within the East Texas/North Louisiana region were operated by third party oil and natural gas companies. These Third Party Operators often use hydraulic fracturing as a means to maximize the productivity of oil and natural gas wells. Hydraulic fracturing involves the injection of water, sand and additives under pressure into rock formations in order to stimulate natural gas production. The Third Party Operators often find that the use of hydraulic fracturing is necessary to produce commercial quantities of oil and natural gas from the Haynesville Shale. Many of the Third Party Operators have made extensive public disclosure regarding their hydraulic fracturing activities.
 
All of Enduro Sponsor’s acreage in the East Texas/North Louisiana region, or 4,113 net acres, representing approximately 39.7% of the proved reserves associated with the Underlying Properties as of December 31, 2010, is subject to hydraulic fracturing. Although the cost of each well will vary, on average approximately 40% of the total cost of drilling and completing a well to the Haynesville Shale formation is associated with hydraulic fracturing activities. These costs are treated in the same way that all other costs of drilling and completing Enduro Sponsor’s wells are treated and are built into Enduro Sponsor’s normal capital expenditure budget, which is funded through operating cash flows or borrowings under its revolving credit facility. Enduro Sponsor owns an average 26.2% working interest in the Haynesville Shale formations associated with the Underlying Properties. Enduro Sponsor has a total $25 million capital expenditure budget for the East Texas/North Louisiana region, approximately $10 million of which is budgeted for hydraulic fracturing activities.
 
To Enduro Sponsor’s knowledge, there have not been any incidents, citations or suits related to fracturing operations related to environmental concerns on the Underlying Properties. The protection of groundwater quality is extremely important to Enduro Sponsor. Enduro Sponsor has reviewed with the Third Party Operators their responsibilities, plans and policies regarding oil and gas operations and the environment, including hydraulic fracturing. These operators have provided detailed information in their publicly filed documents and on their websites regarding hydraulic fracturing. Enduro Sponsor believes that all of the Third Party Operators using hydraulic fracturing in the East Texas/North Louisiana region follow applicable standard industry practices and legal requirements for groundwater protection. These measures are subject to close supervision by state and federal regulators (including the Bureau of Land Management with respect to federal acreage), who conduct many inspections


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during operations that include hydraulic fracturing. These protective measures include using steel casing pipe and concrete in well construction.
 
Once a pipe is set in place, cement is pumped into the well where it hardens and creates a permanent, isolating barrier between the steel casing pipe and surrounding geological formations. This aspect of the well design is intended to eliminate any “pathway” for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. Furthermore, in the Haynesville Shale, the hydrocarbon bearing formations are generally separated from any usable underground aquifers by thousands of feet of impermeable rock layers. This wide separation serves as a protective barrier, preventing any migration of fracturing fluids or hydrocarbons upwards into any groundwater zones.
 
In addition, the vendors conducting hydraulic fracturing in the East Texas/North Louisiana region monitor all pump rates and pressures during the fracturing treatments. This monitoring occurs on a real-time basis to identify abrupt changes in rate or pressure, which permits the operator to modify or cease the fracturing process.
 
Approximately 99% of typical hydraulic fracturing fluids are made up of water and sand. The Third Party Operators utilize major hydraulic fracturing service companies whose research departments, in cooperation with some Third Party Operators, conduct ongoing development of “greener” chemicals that are used in fracturing.
 
Many Third Party Operators have made arrangements to source a portion of their water needs from recycled industrial waste water. The Third Party Operators are also currently investigating the technology to recycle a significant percentage of the water recovered from hydraulic fracturing operations in the East Texas/North Louisiana region. This recycling greatly lessens the demand on local natural water resources. Enduro Sponsor believes that any water from hydraulic fracturing operations in the East Texas/North Louisiana region that is not recycled is disposed of in a way that does not impact surface waters, generally by means of approved disposal or injection wells. Enduro Sponsor currently does not intentionally discharge any waters to the surface. The Third Party Operators employ other procedures to reduce the impact of water discharge, including ensuring that produced water is contained in surface tanks or open pits that are properly lined to prevent produced water from being released into the environment. Enduro Sponsor supports the Third Party Operators’ activities to operate responsibly and prudently. In many cases, Enduro Sponsor has joint operating agreements that require the operator to act prudently with respect to safety and the environment.
 
For more information on the risks of hydraulic fracturing, please read “Risk Factors — The operations of the Underlying Properties are subject to environmental laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or result in significant costs and liabilities, which could reduce the amount of cash available for distribution to trust unitholders.” and “Risk Factors — Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect the services of the operators of the Underlying Properties.”
 
Marketing and Post-Production Services
 
Pursuant to the terms of the conveyance creating the Net Profits Interest, Enduro Sponsor will have the responsibility to market, or cause to be marketed, the oil and natural gas production attributable to the Net Profits Interest in the Underlying Properties. The terms of the conveyance restrict Enduro Sponsor from charging any fee for marketing production attributable to the Net Profits Interest other than fees for marketing paid to non-affiliates. Accordingly, a marketing fee will not be deducted (other than fees paid to non-affiliates) in the calculation of the Net Profits Interest’s share of net profits. The net profits to the trust from the sales of oil and natural gas production from the Underlying Properties attributable to the Net Profits Interest will be determined based on the same price that Enduro Sponsor receives for sales of oil and natural gas production attributable to Enduro Sponsor’s interest in the Underlying Properties. However, in the event that the oil or natural gas is processed, the net profits will receive the same processing upgrade or downgrade as Enduro Sponsor.


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During the year ended December 31, 2010, the operators of the Underlying Properties sold the oil produced from the Underlying Properties to third-party crude oil purchasers. Oil production from the Underlying Properties is typically transported by truck from the field to the closest gathering facility or refinery. The operators sell the majority of the oil production from the Underlying Properties under contracts using market sensitive pricing. The price received by the operators for the oil production from the Underlying Properties is usually based on a regional price applied to equal daily quantities in the month of delivery that is then reduced for differentials based upon delivery location and oil quality. Enduro Sponsor does not believe that the loss of any of these parties as a purchaser of crude oil production from the Underlying Properties would have a material impact on the business or operations of Enduro Sponsor or the Underlying Properties because of the competitive marketing conditions in Texas, Louisiana and New Mexico.
 
All natural gas produced by the operators is marketed and sold to third-party purchasers. The natural gas is sold pursuant to contracts with such third parties, and the sales contracts are in their secondary terms and are on a month-to-month basis. In all cases, the contract price is based on a percentage of a published regional index price, after adjustments for Btu content, transportation and related charges.
 
Title to Properties
 
The properties comprising the Underlying Properties are or may be subject to one or more of the burdens and obligations described below. To the extent that these burdens and obligations affect Enduro Sponsor’s rights to production or the value of production from the Underlying Properties, they have been taken into account in calculating the trust’s interests and in estimating the size and the value of the reserves attributable to the Underlying Properties.
 
Enduro Sponsor’s interests in the oil and natural gas properties comprising the Underlying Properties are typically subject, in one degree or another, to one or more of the following:
 
  •      royalties and other burdens, express and implied, under oil and natural gas leases and other arrangements;
 
  •      overriding royalties, production payments and similar interests and other burdens created by Enduro Sponsor’s predecessors in title;
 
  •      a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect the Underlying Properties or their title;
 
  •      liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings;
 
  •      pooling, unitization and communitization agreements, declarations and orders;
 
  •      easements, restrictions, rights-of-way and other matters that commonly affect property;
 
  •      conventional rights of reassignment that obligate Enduro Sponsor to reassign all or part of a property to a third party if Enduro Sponsor intends to release or abandon such property;
 
  •      preferential rights to purchase or similar agreements and required third party consents to assignments or similar agreements;
 
  •      obligations or duties affecting the Underlying Properties to any municipality or public authority with respect to any franchise, grant, license or permit, and all applicable laws, rules, regulations and orders of any governmental authority; and


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  •      rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties and also the interests held therein, including Enduro Sponsor’s interests and the Net Profits Interest.
 
Enduro Sponsor believes that the burdens and obligations affecting the properties comprising the Underlying Properties are conventional in the industry for similar properties. Enduro Sponsor also believes that the existing burdens and obligations do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not materially adversely affect the Net Profits Interest or its value.
 
In order to give third parties notice of the Net Profits Interest, Enduro Sponsor will record the conveyance of the Net Profits Interest in Texas, Louisiana and New Mexico in the real property records in each Texas, Louisiana or New Mexico county in which the Underlying Properties are located, or in such other public records of those states as required under applicable law to place third parties on notice of the conveyance.
 
It is well-established under Texas law that the conveyance of a net profits interest constitutes the conveyance of a presently vested, non-possessory interest in real property. Therefore, Enduro Sponsor and the trust believe that, in a bankruptcy of Enduro Sponsor, the Net Profits Interest would be viewed as a separate property interest under Texas law and, as such, outside of Enduro Sponsor’s bankruptcy estate. Likewise, Enduro Sponsor and the trust believe that the Net Profits Interest would be viewed as a separate property interest under the laws of Louisiana and outside of Enduro Sponsor’s bankruptcy estate. Since enactment of the Louisiana Mineral Code in 1975, Louisiana courts have classified an overriding royalty interest as a real right and an incorporeal immovable (similar to a real property interest). Although there are no reported Louisiana court cases addressing whether a net profits interest, carved out of the interest of a mineral lessee under an oil and gas lease, should be similarly classified as a real right and an incorporeal immovable, a 1972 Colorado federal court applying Louisiana law did conclude that such a net profits interest was comparable to an overriding royalty interest and, thus, was properly so classified. Similarly, Enduro Sponsor and the trust believe that a New Mexico court would rule that the conveyance of a net profits interest constitutes a conveyance of a real property interest. While no New Mexico case has clearly defined the nature of a “net profits interest” independent of the creating instrument, New Mexico case law has held that an overriding royalty interest in a mineral lease is a real property interest under New Mexico law. The 10th Circuit Court of Appeals has held that a net profits interest is “similar to” an overriding royalty interest. Given that the conveyance of the Net Profits Interest will contain a provision stating that it is the express intent of the parties that the conveyance of the Net Profits Interest constitutes a conveyance of a royalty interest in real property, in the event of a bankruptcy on the part of Enduro Sponsor, under New Mexico law, the Net Profits Interest would likely not be treated as part of Enduro Sponsor’s bankruptcy estate. Further, it is relevant that Enduro Sponsor and the trust have structured the Net Profits Interest as an overriding royalty interest in gross production payable on the basis of net profits. Nevertheless, the outcome is not certain given that there are not any dispositive Louisiana or New Mexico Supreme Court cases directly concluding that a conveyance of a net profits interest: (i) in the case of Louisiana, constitutes the conveyance of a real right and an incorporeal immovable (similar to a real property interest) or (ii) in the case of New Mexico, constitutes the conveyance of a real property interest. As such, in a bankruptcy of Enduro Sponsor, to the extent Louisiana or New Mexico law were held to be applicable, the Net Profits Interest might be considered an asset of the bankruptcy estate and used to satisfy obligations to creditors of Enduro Sponsor, in which case the trust would be an unsecured creditor of Enduro Sponsor at risk of losing the entire value of the Net Profits Interest to senior creditors.
 
Enduro Sponsor believes that its title to the Underlying Properties is, and the trust’s title to the Net Profits Interest will be, good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions as are not so material to detract substantially from the use or value of such properties or royalty interests. Under the terms of the conveyance creating the Net Profits Interest, Enduro Sponsor has provided a special warranty of title with respect to the Net Profits


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Interest, subject to the burdens and obligations described in this section. Please see “Risk Factors — The trust units may lose value as a result of title deficiencies with respect to the Underlying Properties.”
 
Competition and Markets
 
The oil and natural gas industry is highly competitive. Enduro Sponsor competes with major oil and natural gas companies and independent oil and natural gas companies for oil and natural gas, equipment, personnel and markets for the sale of oil and natural gas. Many of these competitors are financially stronger than Enduro Sponsor, but even financially troubled competitors can affect the market because of their need to sell oil and natural gas at any price to attempt to maintain cash flow. The trust will be subject to the same competitive conditions as Enduro Sponsor and other companies in the oil and natural gas industry.
 
Oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.
 
Future price fluctuations for oil and natural gas will directly impact trust distributions, estimates of reserves attributable to the trust’s interests and estimated and actual future net revenues to the trust. In view of the many uncertainties that affect the supply and demand for oil and natural gas, neither the trust nor Enduro Sponsor can make reliable predictions of future oil and natural gas supply and demand, future product prices or the effect of future product prices on the trust.
 
Environmental Matters and Regulation
 
General.  The oil and natural gas exploration and production operations of Enduro Sponsor are subject to stringent and comprehensive federal, regional, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose significant obligations on Enduro Sponsor’s operations, including requirements to:
 
  •      obtain permits to conduct regulated activities;
 
  •      limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;
 
  •      restrict the types, quantities and concentration of materials that can be released into the environment in the performance of drilling and production activities;
 
  •      initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as restoration of drilling pits and plugging of abandoned wells;
 
  •      apply specific health and safety criteria addressing worker protection; and
 
  •      impose substantial liabilities on Enduro Sponsor for pollution resulting from Enduro Sponsor’s operations.
 
Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of joint and several liability, investigatory and remedial obligations, and the issuance of injunctions limiting or prohibiting some or all of Enduro Sponsor’s operations. Moreover, these laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Enduro Sponsor believes that it is in substantial compliance with all existing environmental laws and regulations applicable to its current operations


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and that its continued compliance with existing requirements will not have a material adverse effect on the cash distributions to the trust unitholders. However, the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation obligations could have a material adverse effect on Enduro Sponsor’s development expenses, results of operations and financial position. Enduro Sponsor may be unable to pass on those increases to its customers. Moreover, accidental releases or spills may occur in the course of Enduro Sponsor’s operations, and Enduro Sponsor cannot assure you that it will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.
 
The following is a summary of certain existing environmental, health and safety laws and regulations, each as amended from time to time, to which Enduro Sponsor’s business operations are subject.
 
Hazardous substance and wastes.  The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA,” also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. Under CERCLA, these “responsible persons” may include the owner or operator of the site where the release occurred, and entities that transport, dispose of or arrange for the transport or disposal of hazardous substances released at the site. These responsible persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Enduro Sponsor generates materials in the course of its operations that may be regulated as hazardous substances.
 
The Resource Conservation and Recovery Act, or “RCRA,” and comparable state laws regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, production and development of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes (“E&P Wastes”) now classified as non-hazardous could be classified as hazardous wastes in the future. In September 2010, the Natural Resources Defense Council filed a petition with the EPA to request reconsideration of the exemption of E&P Wastes from regulation as hazardous waste under RCRA (which could also affect E&P Wastes’ regulation under other environmental laws, including CERCLA). Any such change could result in an increase in the costs to manage and dispose of wastes, which could have a material adverse effect on the cash distributions to the trust unitholders. In addition, Enduro Sponsor generates industrial wastes in the ordinary course of its operations that may be regulated as hazardous wastes.
 
The real properties upon which Enduro Sponsor conducts its operations have been used for oil and natural gas exploration and production for many years. Although Enduro Sponsor may have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons and wastes may have been disposed of or released on or under the real properties upon which Enduro Sponsor conducts its operations, or on or under other, offsite locations, where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. In addition, the real properties upon which Enduro Sponsor conducts its operations may have been operated by third


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parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under Enduro Sponsor’s control. These real properties and the petroleum hydrocarbons and wastes disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, Enduro Sponsor could be required to remove or remediate previously disposed wastes, to clean up contaminated property and to perform remedial operations such as restoration of pits and plugging of abandoned wells to prevent future contamination or to pay some or all of the costs of any such action.
 
Water discharges and hydraulic fracturing.  The Federal Water Pollution Control Act, also known as the “Clean Water Act,” and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure, or SPCC, plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws required individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Oil Pollution Act of 1990, as amended, or OPA, amends the Clean Water Act and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the United States. OPA requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst case discharge of oil into waters of the United States.
 
In addition, naturally occurring radioactive material (“NORM”) is brought to the surface in connection with oil and gas production. Concerns have arisen over traditional NORM disposal practices (including discharge through publicly owned treatment works into surface waters), which may increase the costs associated with management of NORM.
 
It is customary to recover oil and natural gas from deep shale and tight sand formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Legislation called the FRAC Act has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012. The results of this study could spur further action toward federal legislation and regulation of hydraulic fracturing activities. Other federal agencies are examining hydraulic fracturing, including the U.S. DOE, the U.S. Government Accountability Office and the White House Council for Environmental Quality, and the U.S. Department of the Interior is also considering regulation of hydraulic fracturing activities on public lands. In addition, legislation called the FRAC Act has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including states in which Enduro Sponsor operates. For example, on June 17, 2011, Texas signed into law a bill that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production) and the public. In addition, at least three local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities. Disclosures of chemicals used in the


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hydraulic fracturing process could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could make it more difficult or costly for Enduro Sponsor to perform hydraulic fracturing activities. Moreover, Enduro Sponsor believes that enactment of legislation regulating hydraulic fracturing at the federal level may have a material adverse effect on its business. In addition, the EPA recently took the position that hydraulic fracturing operations using diesel are subject to regulation under the Underground Injection Control program of the Safe Drinking Water Act as Class II wells. Such regulation could result in increased costs and operational delays for certain hydraulic fracturing operations.
 
Air emissions.  The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources through air emissions permitting programs and also impose various monitoring and reporting requirements. These laws and regulations may require Enduro Sponsor to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or incur development expenses to install and utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies may impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.
 
Climate change.  Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” or “GHGs,” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to the scientific studies, international negotiations to address climate change have occurred. The United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” became effective on February 16, 2005 as a result of these negotiations, but the United States did not ratify the Kyoto Protocol. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17 percent compared to 2005 levels.
 
Both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. Although it is not possible at this time to predict when Congress may pass climate change legislation, any future federal or state laws that may be adopted to address GHG emissions could require Enduro Sponsor to incur increased operating costs and could adversely affect demand for the oil and natural gas Enduro Sponsor produces.
 
In addition, on December 15, 2009, the EPA published its findings that emissions of GHGs present an endangerment to public heath and the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of regulations under the Clean Air Act. The first limits emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards take effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under PSD and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that


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facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that have yet to be developed. In December 2010, the EPA promulgated Federal Implementation Plans to establish GHG permitting under the PSD program in several jurisdictions in which applicable State Implementation Plans did not accommodate the regulation of GHGs. In many other jurisdictions, applicable State Implementation Plans may provide for GHG permitting under the PSD program. In addition, on November 30, 2010, the EPA published its final rule expanding the existing GHG monitoring and reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. Reporting of GHG emissions from such facilities will be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. The Underlying Properties may be subject to these requirements or become subject to them in the future.
 
Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact Enduro Sponsor’s operations. In addition to these regulatory developments, recent judicial decisions that have allowed certain tort claims alleging property damage to proceed against GHG emissions sources may increase Enduro Sponsor’s litigation risk for such claims. The adoption of any future regulations that require reporting of GHGs or otherwise limit emissions of GHGs from the equipment and operations of Enduro Sponsor could require Enduro Sponsor to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with its operations, and such requirements also could adversely affect demand for the oil and natural gas that Enduro Sponsor produces.
 
Legislation or regulations that may be adopted to address climate change could also affect the markets for Enduro Sponsor’s products by making its products more or less desirable than competing sources of energy. To the extent that its products are competing with higher greenhouse gas emitting energy sources, Enduro Sponsor’s products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. To the extent that its products are competing with lower greenhouse gas emitting energy, Enduro Sponsor’s products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. Enduro Sponsor cannot predict with any certainty at this time how these possibilities may affect its operations.
 
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 adversely affect or delay demand for the oil or natural gas produced by Enduro Sponsor or otherwise cause Enduro Sponsor to incur significant costs in preparing for or responding to those effects.
 
National Environmental Policy Act.  Oil and natural gas exploration, development and production activities on federal lands are subject to the National Environmental Policy Act, as amended, or NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. However, for those current activities as well as for future or proposed exploration and development plans on federal lands, governmental permits or authorizations that are subject to the requirements of NEPA are required. This process has the potential to delay the development of oil and natural gas projects.
 
Endangered Species Act.  The federal Endangered Species Act, or “ESA,” restricts activities that may affect endangered and threatened species or their habitats. The designation of previously unidentified endangered or threatened species could cause Enduro Sponsor to incur additional costs or become subject to operating delays, restrictions or bans in the affected areas. For example, the


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U.S. Fish and Wildlife Service has proposed to list as “endangered” the dunes sagebrush lizard (Sceloporus arenicolus), whose habitat is understood to include areas in West Texas and southeast New Mexico in which some of the Underlying Properties are located. While some of Enduro Sponsor’s facilities or leased acreage may be located in areas that are or will be designated as habitat for endangered or threatened species, Enduro Sponsor believes that it is in substantial compliance with the ESA.
 
Employee health and safety.  The operations of Enduro Sponsor are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. Enduro Sponsor believes that it is in substantial compliance with all applicable laws and regulations relating to worker health and safety.


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COMPUTATION OF NET PROFITS
 
The provisions of the conveyance governing the computation of the net profits are detailed and extensive. The following information summarizes the material information contained in the conveyance related to the computation of the net profits. This summary may not contain all information that is important to you. For more detailed provisions concerning the Net Profits Interest, you should read the conveyance. A copy of the conveyance has been filed as an exhibit to the registration statement. See “Where You Can Find More Information.”
 
Net Profits Interest
 
The amounts paid to the trust for the Net Profits Interest are based on, among other things, the definitions of “gross profits” and “net profits” contained in the conveyance and described below. Under the conveyance, net profits are computed monthly, and 80% of the aggregate net profits attributable to the sale of oil and natural gas production from the Underlying Properties for each calendar month will be paid to the trust on or before the end of the following month. Enduro Sponsor will not pay to the trust any interest on the net profits held by Enduro Sponsor prior to payment to the trust, provided that such payments are timely made. The trustee will make distributions to trust unitholders monthly. See “Description of the Trust Units — Distributions and Income Computations.”
 
“Gross profits” means the aggregate amount received by Enduro Sponsor from sales of oil and natural gas produced from the Underlying Properties that are not attributable to a production month that occurs prior to May 1, 2011 (after deducting the appropriate share of all royalties and any overriding royalties, production payments and other similar charges (in each case, in existence as of May 1, 2011) and other than certain excluded proceeds, as described in the conveyance), including all proceeds and consideration received (i) directly or indirectly, for advance payments, (ii) directly or indirectly, under take-or-pay and similar provisions of production sales contracts (when credited against the price for delivery of production) and (iii) under balancing arrangements. Gross profits do not include consideration for the transfer or sale of any Underlying Property by Enduro Sponsor or any subsequent owner to any new owner, unless the Net Profits Interest is released (as is permitted under certain circumstances). Gross profit also does not include any amount for oil or natural gas lost in production or marketing or used by the owner of the Underlying Properties in drilling, production and plant operations.
 
“Net profits” means gross profits less the following costs, expenses and, where applicable, losses, liabilities and damages all as actually incurred by Enduro Sponsor and attributable to the Underlying Properties on or after May 1, 2011 but that are not attributable to a production month that occurs prior to May 1, 2011 (as such items are reduced by any offset amounts, as described in the conveyance):
 
  •  with the exception of certain costs and expenses related to 21 wells identified in the conveyance (please read “Projected Cash Distributions — Significant Assumptions Used to Prepare the Projected Cash Distributions — Net adjustment for additional projects”), all costs for (i) drilling, development, production and abandonment operations, (ii) all direct labor and other services necessary for drilling, operating, producing and maintaining the Underlying Properties and workovers of any wells located on the Underlying Properties, (iii) treatment, dehydration, compression, separation and transportation, (iv) all materials purchased for use on, or in connection with, any of the Underlying Properties and (v) any other operations with respect to the exploration, development or operation of hydrocarbons from the Underlying Properties;
 
  •  all losses, costs, expenses, liabilities and damages with respect to the operation or maintenance of the Underlying Properties for (i) defending, prosecuting, handling, investigating or settling litigation, administrative proceedings, claims, damages, judgments, fines, penalties and other liabilities, (ii) the payment of certain judgments, penalties and other liabilities, (iii) the payment or restitution of any proceeds of hydrocarbons from the Underlying Properties, (iv) complying with applicable local, state and federal statutes, ordinances, rules and regulations, (v) tax or royalty audits and (vi) any other loss, cost, expense, liability or damage with respect to the Underlying Properties not paid or reimbursed under insurance;


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  •  all taxes, charges and assessments (excluding federal and state income, transfer, mortgage, inheritance, estate, franchise and like taxes) with respect to the ownership of, or production of hydrocarbons from, the Underlying Properties;
 
  •  all insurance premiums attributable to the ownership or operation of the Underlying Properties for insurance actually carried with respect to the Underlying Properties, or any equipment located on any of the Underlying Properties, or incident to the operation or maintenance of the Underlying Properties;
 
  •  all amounts and other consideration for (i) rent and the use of or damage to the surface, (ii) delay rentals, shut-in well payments and similar payments and (iii) fees for renewal, extension, modification, amendment, replacement or supplementation of the leases included in the Underlying Properties;
 
  •  all amounts charged by the relevant operator as overhead, administrative or indirect charges specified in the applicable operating agreements or other arrangements covering the Underlying Properties or Enduro Sponsor’s operations with respect thereto;
 
  •  to the extent that Enduro Sponsor is the operator of certain of the Underlying Properties and there is no operating agreement covering such portion of the Underlying Properties, those overhead, administrative or indirect charges that are allocated by Enduro Sponsor to such portion of the Underlying Properties;
 
  •  if, as a result of the occurrence of the bankruptcy or insolvency or similar occurrence of any purchaser of hydrocarbons produced from the Underlying Properties, any amounts previously credited to the determination of the net profits are reclaimed from Enduro Sponsor, then the amounts reclaimed;
 
  •  all costs and expenses for recording the conveyance and, at the applicable times, terminations and/or releases thereof;
 
  •  all administrative hedge costs paid after June 30, 2011 (in respect of hedges existing prior to the date of the conveyance, as further described in the conveyance);
 
  •  all hedge settlement costs paid after June 30, 2011 (in respect of hedges existing prior to the date of the conveyance, as further described in the conveyance);
 
  •  amounts previously included in gross profits but subsequently paid as a refund, interest or penalty; and
 
  •  at the option of Enduro Sponsor (or any subsequent owner of the Underlying Properties), amounts reserved for approved development expenditure projects, including well drilling, recompletion and workover costs, which amounts will at no time exceed $2.0 million in the aggregate, and will be subject to the limitations described below (provided that such costs shall not be debited from gross profits when actually incurred).
 
As mentioned above, the costs deducted in the net profits determination will be reduced by certain offset amounts. The offset amounts are further described in the conveyance, and include, among other things, certain net proceeds attributable to the treatment or processing of hydrocarbons produced from the Underlying Properties, all of the hedge payments received by Enduro Sponsor after June 30, 2011 from hedge contract counterparties upon settlement of hedge contracts and certain other non-production revenues, including salvage value for equipment related to plugged and abandoned wells. If the offset amounts exceed the costs during a monthly period, the ability to use such excess amounts to offset costs will be deferred and utilized as offsets in the next monthly period to the extent such amounts, plus accrued interest thereon, together with other offsets to costs, for the applicable month, are less than the costs arising in such month.
 
The trust is not liable to the owners of the Underlying Properties or the operators for any operating, capital or other costs or liabilities attributable to the Underlying Properties. In the event that the net profits


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for any computation period is a negative amount, the trust will receive no payment for that period, and any such negative amount plus accrued interest will be deducted from gross profits in the following computation period for purposes of determining the net profits for that following computation period.
 
Gross profits and net profits are calculated on a cash basis, except that certain costs, primarily ad valorem taxes and expenditures of a material amount, may be determined on an accrual basis.
 
Additional Provisions
 
If a controversy arises as to the sales price of any production, then for purposes of determining gross profits:
 
  •  any proceeds that are withheld for any reason (other than at the request of Enduro Sponsor) are not considered received until such time that the proceeds are actually collected;
 
  •  amounts received and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until disbursed to it by the escrow agent; and
 
  •  amounts received and not deposited with an escrow agent will be considered to have been received.
 
The trustee is not obligated to return any cash received from the Net Profits Interest. Any overpayments made to the trust by Enduro Sponsor due to adjustments to prior calculations of net profits or otherwise will reduce future amounts payable to the trust until Enduro Sponsor recovers the overpayments plus interest at a prime rate (as described in the conveyance).
 
The conveyance generally permits Enduro Sponsor to transfer without the consent or approval of the trust unitholders all or any part of its interest in the Underlying Properties, subject to the Net Profits Interest. The trust unitholders are not entitled to any proceeds of a sale or transfer of Enduro Sponsor’s interest. Except in certain cases where the Net Profits Interest is released, following a sale or transfer, the Underlying Properties will continue to be subject to the Net Profits Interest, and the gross profits attributable to the transferred property will be calculated (as part of the computation of net profits described in this prospectus), paid and distributed by the transferee to the trust. Enduro Sponsor will have no further obligations, requirements or responsibilities with respect to any such transferred interests.
 
In addition, Enduro Sponsor may, without the consent of the trust unitholders, require the trust to release the Net Profits Interest associated with any lease that accounts for less than or equal to 0.25% of the total production from the Underlying Properties in the prior 12 months, provided that the Net Profits Interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the trust of $500,000. These releases will be made only in connection with a sale by Enduro Sponsor to a non-affiliate of the relevant Underlying Properties and are conditioned upon an amount equal to the fair value to the trust of such Net Profits Interest being treated as an offset amount against costs and expenses. Enduro Sponsor has not identified for sale any of the Underlying Properties.
 
As the designated operator of a property comprising the Underlying Properties, Enduro Sponsor may enter into farm-out, operating, participation and other similar agreements to develop the property, but any transfers made in connection with such agreements will be made subject to the Net Profits Interest. Enduro Sponsor may enter into any of these agreements without the consent or approval of the trustee or any trust unitholder.
 
Enduro Sponsor will have the right to release, surrender or abandon its interest in any Underlying Property that will no longer produce (or be capable of producing) hydrocarbons in paying quantities (determined without regard to the Net Profits Interest). Upon such release, surrender or abandonment, the portion of the Net Profits Interest relating to the affected property will also be released, surrendered or abandoned, as applicable. Enduro Sponsor will also have the right to abandon an interest in the Underlying Properties if (a) such abandonment is necessary for health, safety or environmental reasons or (b) the hydrocarbons that would have been produced from the abandoned


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portion of the Underlying Properties would reasonably be expected to be produced from wells located on the remaining portion of the Underlying Properties.
 
Enduro Sponsor must maintain books and records sufficient to determine the amounts payable for the Net Profits Interest to the trust. Monthly and annually, Enduro Sponsor must deliver to the trustee a statement of the computation of the net profits for each computation period. The trustee has the right to inspect and review the books and records maintained by Enduro Sponsor during normal business hours and upon reasonable notice.


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DESCRIPTION OF THE TRUST AGREEMENT
 
The following information and the information included under “Description of the Trust Units” summarize the material information contained in the trust agreement and the conveyance. For more detailed provisions concerning the trust and the conveyance, you should read the trust agreement and the conveyance, forms of which are filed as exhibits to the registration statement. See “Where You Can Find More Information.”
 
Creation and Organization of the Trust; Amendments
 
Immediately prior to the closing of this offering, Enduro Sponsor will convey, or cause to be conveyed, to the trust the Net Profits Interest in consideration of the receipt of 33,000,000 trust units. The trust’s first monthly distribution will consist of an amount in cash paid by Enduro Sponsor equal to the amount that would have been payable to the trust had the Net Profits Interest been in effect beginning on May 1, 2011, less any general and administrative expenses and reserves of the trust. After the offering made hereby, Enduro Sponsor will own its net interests in the Underlying Properties subject to and burdened by the Net Profits Interest.
 
The trust was created under Delaware law to acquire and hold the Net Profits Interest for the benefit of the trust unitholders pursuant to an agreement among Enduro Sponsor, the trustee and the Delaware trustee. The Net Profits Interest is passive in nature and neither the trust nor the trustee has any control over or responsibility for costs relating to the operation of the properties comprising the Underlying Properties. Except as described below under “— Fees and Expenses”, neither Enduro Sponsor nor any of the Third Party Operators have any contractual commitments to the trust to provide additional funding or to conduct further drilling on or to maintain their ownership interest in any of the Underlying Properties. After the conveyance of the Net Profits Interest, however, Enduro Sponsor will retain an interest in the Underlying Properties. For a description of the Underlying Properties and other information relating to them, see “The Underlying Properties.”
 
The trust agreement will provide that the trust’s business activities will be limited to owning the Net Profits Interest and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyance related to the Net Profits Interest. As a result, the trust will not be permitted to acquire other oil and natural gas properties or net profits interests or otherwise to engage in activities beyond those necessary for the conservation and protection of the Net Profits Interest.
 
The beneficial interest in the trust is divided into 33,000,000 trust units. Each of the trust units represents an equal undivided beneficial interest in the assets of the trust. You will find additional information concerning the trust units in “Description of the Trust Units.”
 
Amendment of the trust agreement requires the affirmative vote of the holders of at least 75% of the outstanding trust units. However, no amendment may:
 
  •      increase the power of the trustee or the Delaware trustee to engage in business or investment activities; or
 
  •      alter the rights of the trust unitholders as among themselves.
 
In addition, certain sections of the trust agreement cannot be amended without the consent of Enduro Sponsor. Certain amendments to the trust agreement do not require the vote of the trust unitholders. The trustee may, without approval of the trust unitholders, from time to time supplement or amend the trust agreement in order to cure any ambiguity, to correct or supplement any defective or inconsistent provisions, to grant any benefit to all of the trust unitholders, to comply with changes in applicable law or to change the name of the trust, provided such supplement or amendment does not materially adversely affect the interests of the trust unitholders. The affairs of the trust will be managed by the trustee. Enduro Sponsor has no ability to manage or influence the operations of the


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trust and will not owe any fiduciary duties or liabilities to the trust or the unitholders. Likewise, the trust has no ability to manage or influence the operation of Enduro Sponsor.
 
Assets of the Trust
 
Upon completion of this offering, the assets of the trust will consist of the Net Profits Interest and any cash and temporary investments being held for the payment of expenses and liabilities and for distribution to the trust unitholders.
 
Duties and Powers of the Trustee
 
The duties of the trustee are specified in the trust agreement and by the laws of the state of Delaware, except as modified by the trust agreement. The trustee’s principal duties consist of:
 
  •      collecting cash attributable to the Net Profits Interest;
 
  •      paying expenses, charges and obligations of the trust from the trust’s assets;
 
  •      distributing distributable cash to the trust unitholders;
 
  •      causing to be prepared and distributed a tax information report for each trust unitholder and to prepare and file tax returns on behalf of the trust;
 
  •      causing to be prepared and filed reports required to be filed under the Exchange Act and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading;
 
  •      causing to be prepared and filed a reserve report by or for the trust by independent reserve engineers as of December 31 of each year in accordance with criteria established by the SEC;
 
  •      establishing, evaluating and maintaining a system of internal control over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002;
 
  •      enforcing the rights under certain agreements entered into in connection with this offering; and
 
  •      taking any action it deems necessary, desirable or advisable to best achieve the purposes of the trust.
 
In connection with the formation of the trust, the trust will enter into several agreements with Enduro Sponsor that impose obligations upon Enduro Sponsor that are enforceable by the trustee on behalf of the trust, including a conveyance and a registration rights agreement. The trustee has the power and authority under the trust agreement to enforce these agreements on behalf of the trust. Additionally, the trustee may from time to time supplement or amend the conveyance and the registration rights agreement to which the trust is a party without the approval of trust unitholders in order to cure any ambiguity, to correct or supplement any defective or inconsistent provisions, to grant any benefit to all of the trust unitholders, to comply with changes in applicable law or to change the name of the trust. Such supplement or amendment, however, may not materially adversely affect the interests of the trust unitholders.
 
The trustee may create a cash reserve to pay for future liabilities of the trust. If the trustee determines that the cash on hand and the cash to be received are, or will be, insufficient to cover the trust’s liabilities, the trustee may cause the trust to borrow funds to pay liabilities of the trust. The trustee may cause the trust to borrow the funds from any person, including itself or its affiliates. The trustee may also cause the trust to mortgage its assets to secure payment of the indebtedness. The terms of such indebtedness and security interest, if funds were loaned by the entity serving as trustee or Delaware trustee or an affiliate thereof, would be similar to the terms which such entity would grant


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to a similarly situated commercial customer with whom it did not have a fiduciary relationship, and such entity shall be entitled to enforce its rights with respect to any such indebtedness and security interest as if it were not then serving as trustee or Delaware trustee. If the trustee causes the trust to borrow funds, the trust unitholders will not receive distributions until the borrowed funds are repaid.
 
Each month, the trustee will pay trust obligations and expenses and distribute to the trust unitholders the remaining proceeds received from the Net Profits Interest. The cash held by the trustee as a reserve against future liabilities or for distribution at the next distribution date must be invested in:
 
  •      interest bearing obligations of the United States government;
 
  •      money market funds that invest only in United States government securities;
 
  •      repurchase agreements secured by interest-bearing obligations of the United States government; or
 
  •      bank certificates of deposit.
 
Alternatively, cash held for distribution at the next distribution date may be held in a non-interest bearing account.
 
The trust may not acquire any asset except the Net Profits Interest, cash and temporary cash investments, and it may not engage in any investment activity except investing cash on hand.
 
The trust may merge or consolidate with or convert into one or more limited partnerships, general partnerships, corporations, statutory trusts, common law trusts, limited liability companies, associations or unincorporated businesses if such transaction is agreed to by the trustee and by the affirmative vote of the holders of a majority of the trust units present in person or by proxy at a meeting of such holders where a quorum is present and such transaction is permitted under the Delaware Statutory Trust Act and any other applicable law.
 
Enduro Sponsor may cause the trustee to sell all or any part of the trust estate, including all or any portion of the Net Profits Interest, if approved by the holders of at least 75% of the outstanding trust units. In addition, Enduro Sponsor may, without the consent of the trust unitholders, require the trust to release the Net Profits Interest associated with any lease that accounts for less than or equal to 0.25% of the total production from the Underlying Properties in the prior 12 months, provided that the Net Profits Interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the trust of $500,000. These releases will be made only in connection with a sale by Enduro Sponsor to a non-affiliate of the relevant Underlying Properties and are conditioned upon an amount equal to the fair value to the trust of such Net Profits Interest being treated as an offset amount against costs and expenses.
 
Upon dissolution of the trust, the trustee must sell the Net Profits Interest. No trust unitholder approval is required in this event.
 
The trustee may require any trust unitholder to dispose of his trust units if an administrative or judicial proceeding seeks to cancel or forfeit any of the property in which the trust holds an interest because of the nationality or any other status of that trust unitholder. If a trust unitholder fails to dispose of his trust units, the trustee has the right to purchase them on behalf of the trust and to borrow funds to make that purchase.
 
The trustee will be required by the NYSE to maintain a website for filings made by the trust with the SEC.
 
The trustee may agree to modifications of the terms of the conveyance or to settle disputes involving the conveyance without the consent of any trust unitholder. The trustee may not agree to modifications or settle disputes involving the Net Profits Interest part of the conveyance if these actions would change the character of the Net Profits Interest in such a way that the Net Profits Interest


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becomes a working interest or that the trust would fail to continue to qualify as a grantor trust for U.S. federal income tax purposes.
 
Fees and Expenses
 
Because the trust does not conduct an active business and the trustee has little power to incur obligations, it is expected that the trust will only incur liabilities for routine administrative expenses, such as the trustee’s fees, accounting, engineering, legal, tax advisory and other professional fees and other fees and expenses applicable to public companies. The trust will also be responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual, quarterly and monthly reports to trust unitholders, tax return and Form 1099 preparation and distribution, NYSE listing fees, independent auditor fees and registrar and transfer agent fees. These general and administrative expenses are anticipated to be approximately $850,000 for 2011. Enduro Sponsor has agreed to provide certain administrative services to the trust. Enduro Sponsor will not receive any compensation for the services. Enduro Sponsor is obligated to provide these services pursuant to the trust agreement. General and administrative expenses for subsequent years could be greater or less depending on future events that cannot be predicted. Included in the $850,000 annual estimate is an annual administrative fee of $200,000 and $2,000 for the trustee and Delaware trustee, respectively. See “The Trust.” The trust will pay, out of the first cash payment received by the trust, the trustee’s and Delaware trustee’s legal expenses incurred in forming the trust as well as their acceptance fees in the amount of $10,000 and $1,500, respectively. These costs will be deducted by the trust before distributions are made to trust unitholders.
 
Enduro Sponsor has agreed to provide the trust at the closing of this offering with a $1 million letter of credit to be used by the trust in the event that its cash on hand (including available cash reserves) is not sufficient to pay ordinary course administrative expenses as they become due. Further, if the trust requires more than the $1 million under the letter of credit to pay administrative expenses, Enduro Sponsor has agreed to loan funds to the trust necessary to pay such expenses. Any funds provided under the letter of credit or loaned by Enduro Sponsor may only be used for the payment of current accounts or other obligations to trade creditors in connection with obtaining goods or services or for the payment of other accrued current liabilities arising in the ordinary course of the trust’s business, and may not be used to satisfy trust indebtedness. If the trust draws on the letter of credit or Enduro Sponsor loans funds to the trust, no further distributions will be made to trust unitholders (except in respect of any previously determined monthly cash distribution amount) until such amounts drawn or borrowed are repaid. Any loan made by Enduro Sponsor will be on an unsecured basis, and the terms of such loan will be substantially the same as those which would be obtained in an arm’s-length transaction between Enduro Sponsor and an unaffiliated third party.
 
Fiduciary Responsibility and Liability of the Trustee
 
The trustee will not make business or investment decisions affecting the assets of the trust except to the extent it enforces its rights under the conveyance agreement related to the Net Profits Interest described above under “— Duties and Powers of the Trustee” that will be executed in connection with this offering. Therefore, substantially all of the trustee’s functions under the trust agreement are expected to be ministerial in nature. See “— Duties and Powers of the Trustee” above. The trust agreement, however, provides that the trustee may:
 
  •      charge for its services as trustee;
 
  •      retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the trustee to the extent permitted by law);
 
  •      lend funds at commercial rates to the trust to pay the trust’s expenses; and
 
  •      seek reimbursement from the trust for its out-of-pocket expenses.
 
In discharging its duty to trust unitholders, the trustee may act in its discretion and will be liable to the trust unitholders only for its own fraud, gross negligence or willful misconduct. The


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trustee will not be liable for any act or omission of its agents or employees unless the trustee acted with fraud, gross negligence or willful misconduct in their selection, retention or supervision. The trustee will be indemnified individually or as the trustee for any liability or cost that it incurs in the administration of the trust, except in cases of fraud, gross negligence or willful misconduct. The trustee will have a lien on the assets of the trust as security for this indemnification and its compensation earned as trustee. Trust unitholders will not be liable to the trustee for any indemnification. See “Description of the Trust Units — Liability of Trust Unitholders.”
 
The trustee may consult with counsel, accountants, tax advisors, geologists, engineers and other parties the trustee believes to be qualified as experts on the matters for which advice is sought. The trustee will be protected in relying or reasonably acting upon the opinion of the expert.
 
Except as expressly set forth in the trust agreement, neither Enduro Sponsor, the trustee, the Delaware trustee nor the other indemnified parties have any duties or liabilities, including fiduciary duties, to the trust or any trust unitholder. The provisions of the trust agreement, to the extent they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties of these persons otherwise existing at law or in equity, are agreed by the trust unitholders to replace such other duties and liabilities of these persons.
 
Duration of the Trust; Sale of the Net Profits Interest
 
The trust will dissolve upon the earliest to occur of the following:
 
  •      the trust, upon the approval of the holders of at least 75% of the outstanding trust units, sells the Net Profits Interest;
 
  •      the annual cash available for distribution to the trust is less than $2 million for each of any two consecutive years;
 
  •      the holders of at least 75% of the outstanding trust units vote in favor of dissolution; or
 
  •      the trust is judicially dissolved.
 
The trustee would then sell all of the trust’s assets, either by private sale or public auction, and, after payment or the making of reasonable provision for payment of all liabilities of the trust, distribute the net proceeds of the sale to the trust unitholders.
 
Dispute Resolution
 
Any dispute, controversy or claim that may arise between Enduro Sponsor and the trustee relating to the trust will be submitted to binding arbitration before a tribunal of three arbitrators.
 
Compensation of the Trustee and the Delaware Trustee
 
The trustee’s and the Delaware trustee’s compensation will be paid out of the trust’s assets. See “— Fees and Expenses.”
 
Miscellaneous
 
The principal offices of the trustee are located at 919 Congress Avenue, Suite 500, Austin, Texas 78701, and its telephone number is 1-800-852-1422.
 
The Delaware trustee and the trustee may resign at any time or be removed with or without cause at any time by the affirmative vote of not less than a majority of the trust units present in person or by proxy at a meeting of such holders where a quorum is present. Any successor must be a bank or trust company meeting certain requirements including having combined capital, surplus and undivided profits of at least $20,000,000, in the case of the Delaware trustee, and $100,000,000, in the case of the trustee.


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DESCRIPTION OF THE TRUST UNITS
 
Each trust unit is a unit of beneficial interest in the trust assets and is entitled to receive cash distributions from the trust on a pro rata basis. Each trust unitholder has the same rights regarding each of his trust units as every other trust unitholder has regarding his units. The trust units will be in book-entry form only and will not be represented by certificates. The trust will have 33,000,000 trust units outstanding upon completion of this offering.
 
Distributions and Income Computations
 
Each month, the trustee will determine the amount of funds available for distribution to the trust unitholders. Available funds are the excess cash, if any, received by the trust from the Net Profits Interest and other sources (such as interest earned on any amounts reserved by the trustee) that month, over the trust’s liabilities for that month. Available funds will be reduced by any cash the trustee decides to hold as a reserve against future liabilities. The holders of trust units as of the applicable record date (generally the 15th day of each calendar month) are entitled to monthly distributions payable on or before the 10th business day after the record date. The first distribution to trust unitholders purchasing trust units in this offering will be made on or about October 28, 2011 to trust unitholders owning trust units on or about October 14, 2011.
 
Unless otherwise advised by counsel or the IRS, the trustee will treat the income and expenses of the trust for each month as belonging to the trust unitholders of record on the monthly record date. Trust unitholders generally will recognize income and expenses for tax purposes in the month the trust receives or pays those amounts, rather than in the month the trust distributes the cash to which such income or expenses (as applicable) relate. Minor variances may occur. For example, the trustee could establish a reserve in one month that would not result in a tax deduction until a later month. See “Federal Income Tax Consequences.”
 
Transfer of Trust Units
 
Trust unitholders may transfer their trust units in accordance with the trust agreement. The trustee will not require either the transferor or transferee to pay a service charge for any transfer of a trust unit. The trustee may require payment of any tax or other governmental charge imposed for a transfer. The trustee may treat the owner of any trust unit as shown by its records as the owner of the trust unit. The trustee will not be considered to know about any claim or demand on a trust unit by any party except the record owner. A person who acquires a trust unit after any monthly record date will not be entitled to the distribution relating to that monthly record date. Delaware law will govern all matters affecting the title, ownership or transfer of trust units.
 
Periodic Reports
 
The trustee will file all required trust federal and state income tax and information returns. The trustee will prepare and mail to trust unitholders annual reports that trust unitholders need to correctly report their share of the income and deductions of the trust. The trustee will also cause to be prepared and filed reports required to be filed under the Exchange Act and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading, and will also cause the trust to comply with all of the provisions of the Sarbanes-Oxley Act, including but not limited to, establishing, evaluating and maintaining a system of internal control over financial reporting in compliance with the requirements of Section 404 thereof.
 
Each trust unitholder and his representatives may examine, for any proper purpose, during reasonable business hours, the records of the trust and the trustee, subject to such restrictions as are set forth in the trust agreement.


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Liability of Trust Unitholders
 
Under the Delaware Statutory Trust Act, trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.
 
Voting Rights of Trust Unitholders
 
The trustee or trust unitholders owning at least 10% of the outstanding trust units may call meetings of trust unitholders. The trust will be responsible for all costs associated with calling a meeting of trust unitholders unless such meeting is called by the trust unitholders, in which case the trust unitholders will be responsible for all costs associated with calling such meeting of trust unitholders. Meetings must be held in such location as is designated by the trustee in the notice of such meeting. The trustee must send notice of the time and place of the meeting and the matters to be acted upon to all of the trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of trust units outstanding must be present or represented to have a quorum. Each trust unitholder is entitled to one vote for each trust unit owned. Abstentions and broker non-votes shall not be deemed to be a vote cast.
 
Unless otherwise required by the trust agreement, a matter may be approved or disapproved by the affirmative vote of a majority of the trust units present in person or by proxy at a meeting where there is a quorum. This is true, even if a majority of the total trust units did not approve it. The affirmative vote of the holders of at least 75% of the outstanding trust units is required to:
 
  •      dissolve the trust;
 
  •      amend the trust agreement (except with respect to certain matters that do not adversely affect the rights of trust unitholders in any material respect); or
 
  •      approve the sale of all or any material part of the assets of the trust (including the sale of the Net Profits Interest).
 
In addition, certain amendments to the trust agreement may be made by the trustee without approval of the trust unitholders. See “Description of the Trust Agreement — Creation and Organization of the Trust; Amendments.”
 
Comparison of Trust Units and Common Stock
 
Trust unitholders have more limited voting rights than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for annual or other periodic re-election of the trustee.


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You should also be aware of the following ways in which an investment in trust units is different from an investment in common stock of a corporation.
 
         
   
Trust Units
 
Common Stock
 
Voting
  The trust agreement provides voting rights to trust unitholders to remove and replace the trustee and to approve or disapprove amendments to the trust agreement and certain major trust transactions.   Unless otherwise provided in the certificate of incorporation, the corporate statutes provide voting rights to stockholders to elect directors and to approve or disapprove amendments to the certificate of incorporation and certain major corporate transactions.
         
Income Tax
  The trust is not subject to income tax; trust unitholders are subject to income tax on their pro rata share of trust income, gain, loss and deduction.   Corporations are taxed on their income and their stockholders are taxed on dividends.
         
Distributions
  Substantially all of the cash receipts of the trust is required to be distributed to trust unitholders.   Unless otherwise provided in the certificate of incorporation, stockholders are entitled to receive dividends solely at the discretion of the board of directors.
         
Business and Assets
  The business of the trust is limited to specific assets with a finite economic life.   Unless otherwise provided in the certificate of incorporation, a corporation conducts an active business for an unlimited term and can reinvest its earnings and raise additional capital to expand.
         
Fiduciary Duties
  The trustee shall not be liable to the trust unitholders for any of its acts or omissions absent its own fraud, gross negligence or willful misconduct.   Officers and directors have a fiduciary duty of loyalty to the corporation and its stockholders and a duty to exercise due care in the management and administration of a corporation’s affairs.


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TRUST UNITS ELIGIBLE FOR FUTURE SALE
 
General
 
Prior to this offering, there has been no public market for the trust units. Sales of substantial amounts of the trust units in the open market, or the perception that those sales could occur, could adversely affect prevailing market prices.
 
Upon completion of this offering, there will be outstanding 33,000,000 trust units. All of the trust units sold in this offering, or 15,180,000 trust units if the underwriters exercise their option to purchase additional trust units in full, will be freely tradable without restriction under the Securities Act of 1933, as amended (the “Securities Act”). All of the trust units outstanding other than the trust units sold in this offering (a total of 19,800,000 trust units, or 17,820,000 trust units if the underwriters exercise their option to purchase additional trust units in full) will be “restricted securities” within the meaning of Rule 144 under the Securities Act and may not be sold other than through registration under the Securities Act or pursuant to an exemption from registration, subject to the restrictions on transfer contained in the lock-up agreements described below and in “Underwriting (Conflicts of Interest).”
 
Lock-Up Agreements
 
In connection with this offering, Enduro Sponsor, and Enduro Sponsor’s officers or managers participating in the directed unit program, have agreed, for a period of 180 days after the date of this prospectus, not to offer, sell, contract to sell or otherwise dispose of or transfer any trust units or any securities convertible into or exchangeable for trust units without the prior written consent of Barclays Capital Inc., subject to specified exceptions. See “Underwriting (Conflicts of Interest)” for a description of these lock-up arrangements. Upon the expiration of these lock-up agreements, 19,800,000 trust units, or 17,820,000 trust units if the underwriters exercise their option to purchase additional trust units in full, will be eligible for sale in the public market under Rule 144 of the Securities Act, subject to volume limitations and other restrictions contained in Rule 144, or through registration under the Securities Act.
 
Rule 144
 
The trust units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any trust units owned by an “affiliate” of the trust, including those held by Enduro Sponsor, may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:
 
  •      1.0% of the total number of the securities outstanding, or
 
  •      the average weekly reported trading volume of the trust units for the four calendar weeks prior to the sale.
 
Sales under Rule 144 are also subject to specific manners of sale provisions, holding period requirements, notice requirements and the availability of current public information about the trust. A person who is not deemed to have been an affiliate of Enduro Sponsor or the trust at any time during the three months preceding a sale, and who has beneficially owned his trust units for at least six months (provided the trust is in compliance with the current public information requirement) or one year (regardless of whether the trust is in compliance with the current public information requirement), would be entitled to sell trust units under Rule 144 without regard to the rule’s public information requirements, volume limitations, manner of sale provisions and notice requirements.


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Registration Rights
 
The trust intends to enter into a registration rights agreement with Enduro Sponsor in connection with Enduro Sponsor’s contribution to the trust of the Net Profits Interest. In the registration rights agreement, the trust will agree, for the benefit of Enduro Sponsor and any transferee of Enduro Sponsor’s trust units (the “holders”), to register the trust units they hold. Specifically, the trust will agree:
 
  •      subject to the restrictions described above under “— Lock-Up Agreements” and under “Underwriting (Conflicts of Interest) — Lock-Up Agreements,” to use its reasonable best efforts to file a registration statement, including, if so requested, a shelf registration statement, with the SEC as promptly as practicable following receipt of a notice requesting the filing of a registration statement from holders representing a majority of the then outstanding registrable trust units;
 
  •      to use its commercially reasonable efforts to cause the registration statement or shelf registration statement to be declared effective under the Securities Act as promptly as practicable after the filing thereof; and
 
  •      to use its commercially reasonable efforts to maintain the effectiveness of the registration statement under the Securities Act for 90 days (or for three years if a shelf registration statement is requested) after the effectiveness thereof or until the trust units covered by the registration statement have been sold pursuant to such registration statement, Enduro Sponsor ceases to be an affiliate of the trust for 10 years or until all registrable trust units:
 
  •      have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities;”
 
  •      have been sold in a private transaction in which the transferor’s rights under the registration rights agreement are not assigned to the transferee of the trust units;
 
  •      are held by the trust; or
 
  •      have been sold in a private transaction in which the transferor’s rights under the registration rights agreement are assigned to a transferee that is not an affiliate of the trust and two years have passed since such transfer.
 
The holders will have the right to require the trust to file no more than five registration statements in aggregate.
 
In connection with the preparation and filing of any registration statement, Enduro Sponsor will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the trust, which will be borne by the trust. Any underwriting discounts and commissions will be borne by the seller of the trust units.


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FEDERAL INCOME TAX CONSEQUENCES
 
U.S. Federal Income Tax Consequences
 
This section is a summary of the material U.S. federal income tax considerations that may be relevant to prospective trust unitholders and, unless otherwise noted in the following discussion, is the opinion of Latham & Watkins LLP, counsel to the trust, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations promulgated under the Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change or different interpretation at any time, possibly with retroactive effect. Later changes in these authorities may cause the U.S. federal income tax consequences to vary substantially from the consequences described below.
 
The following discussion does not comment on all federal income tax matters affecting the trust or trust unitholders. The following discussion is limited to trust unitholders who hold the trust units as “capital assets” (generally, property held for investment). All references to “trust unitholders” (including U.S. trust unitholders and non-U.S. trust unitholders) are to beneficial owners of the trust units. This summary does not address the effect of the U.S. federal estate or gift tax laws or the tax considerations arising under the law of any state (except as provided in the limited summary below under “State Tax Considerations”), local or non-U.S. jurisdiction. Moreover, the discussion has only limited application to trust unitholders subject to special tax treatment such as, without limitation:
 
  •      banks, insurance companies or other financial institutions;
 
  •      trust unitholders subject to the alternative minimum tax;
 
  •      tax-exempt organizations;
 
  •      dealers in securities or commodities;
 
  •      regulated investment companies;
 
  •      real estate investment trusts;
 
  •      traders in securities that elect to use a mark-to-market method of accounting for their securities holdings;
 
  •      non-U.S. trust unitholders (as defined below) that are “controlled foreign corporations” or “passive foreign investment companies”;
 
  •      persons that are S-corporations, partnerships or other pass-through entities;
 
  •      persons that own their interest in the trust units through S-corporations, partnerships or other pass-through entities;
 
  •      persons that at any time own more than 5% of the aggregate fair market value of the trust units;
 
  •      expatriates and certain former citizens or long-term residents of the United States;
 
  •      U.S. trust unitholders (as defined below) whose functional currency is not the U.S. dollar;
 
  •      persons who hold the trust units as a position in a hedging transaction, “straddle,” “conversion transaction” or other risk reduction transaction; or
 
  •      persons deemed to sell the trust units under the constructive sale provisions of the Code.
 
Prospective investors are urged to consult their tax advisors as to the particular tax consequences to them of the ownership and disposition of an investment in trust units, including the applicability of any U.S. federal income, federal estate or gift tax, state, local and foreign tax laws, changes in applicable tax laws and any pending or proposed legislation.


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As used herein, the term “U.S. trust unitholder” means a beneficial owner of trust units that for U.S. federal income tax purposes is:
 
  •      an individual who is a citizen of the United States or who is a resident of the United States for U.S. federal income tax purposes,
 
  •      a corporation, or an entity treated as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the United States, a state thereof or the District of Columbia,
 
  •      an estate the income of which is subject to U.S. federal income taxation regardless of its source, or
 
  •      a trust if it is subject to the primary supervision of a U.S. court and the control of one or more United States persons (as defined for U.S. federal income tax purposes) or that has a valid election in effect under applicable U.S. Treasury regulations to be treated as a United States person.
 
The term “non-U.S. trust unitholder” means any beneficial owner of a trust unit that is an individual, corporation, estate or trust and that is not a U.S. trust unitholder.
 
If a partnership (including for this purpose any entity or arrangement treated as a partnership for U.S. federal income tax purposes) is a beneficial owner of trust units, the tax treatment of a partner in the partnership will depend upon the status of the partner and the activities of the partnership. A trust unitholder that is a partnership, and the partners in such partnership, should consult their own tax advisors about the U.S. federal income tax consequences of purchasing, owning and disposing of trust units.
 
Classification and Taxation of the Trust
 
In the opinion of Latham & Watkins LLP, for U.S. federal income tax purposes, the trust will be treated as a grantor trust and not as an unincorporated business entity. As a grantor trust, the trust will not be subject to tax at the trust level. Rather, the grantors, who in this case are the trust unitholders, will be considered, for U.S. federal income tax purposes, to own and receive the trust’s assets and income and will be directly taxable thereon as though no trust were in existence.
 
No ruling has been or will be requested from the IRS with respect to the U.S. federal income tax treatment of the trust, including a ruling as to the status of the trust as a grantor trust or as a partnership for U.S. federal income tax purposes. Thus, no assurance can be provided that the opinions and statements set forth in this discussion of U.S. federal income tax consequences would be sustained by a court if contested by the IRS.
 
The remainder of the discussion below is based on Latham & Watkins LLP’s opinion that the trust will be classified as a grantor trust for U.S. federal income tax purposes.
 
Reporting Requirements for Widely-Held Fixed Investment Trusts
 
Under Treasury Regulations, the trust is classified as a widely-held fixed investment trust. Those Treasury Regulations require the sharing of tax information among trustees and intermediaries that hold a trust interest on behalf of or for the account of a beneficial owner or any representative or agent of a trust interest holder of fixed investment trusts that are classified as widely-held fixed investment trusts. These reporting requirements provide for the dissemination of trust tax information by the trustee to intermediaries who are ultimately responsible for reporting the investor-specific information through Form 1099 to the investors and the IRS. Every trustee or intermediary that is required to file a Form 1099 for a trust unitholder must furnish a written tax information statement that is in support of the amounts as reported on the applicable Form 1099 to the trust unitholder. Any generic tax information provided by the trustee of the trust is intended to be used only to assist trust unitholders in the preparation of their federal and state income tax returns.


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Direct Taxation of Trust Unitholders
 
Because the trust will be treated as a grantor trust for U.S. federal income tax purposes, trust unitholders will be treated for such purposes as owning a direct interest in the assets of the trust, and each trust unitholder will be taxed directly on his pro rata share of the income and gain attributable to the assets of the trust and will be entitled to claim his pro rata share of the deductions and expenses attributable to the assets of the trust (subject to certain limitations discussed below). Information returns will be filed as required by the widely held fixed investment trust rules, reporting to the trust unitholders all items of income, gain, loss, deduction and credit, which will be allocated based on record ownership on the monthly record dates and must be included in the tax returns of the trust unitholders. Income, gain, loss, deduction and credits attributable to the assets of the trust will be taken into account by trust unitholders consistent with their method of accounting and without regard to the taxable year or accounting method employed by the trust.
 
Following the end of each month, the trustee will determine the amount of funds available as of the end of such month for distribution to the trust unitholders and will make distributions of available funds, if any, to the trust unitholders on or before the 10th business day after the record date, which will generally be on or about the 15th day of each calendar month. In certain circumstances, however, a trust unitholder will not receive a distribution of cash attributable to the income from a month. For example, if the trustee establishes a reserve or borrows money to satisfy liabilities of the trust, income associated with the cash used to establish that reserve or to repay that loan must be reported by the trust unitholder, even though that cash is not distributed to him.
 
As described above, the trust will allocate items of income, gain, loss, deductions and credits to trust unitholders based on record ownership on the monthly record dates. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the trust should be determined and allocated on a daily or prorated basis, which could require adjustments to the tax returns of the unitholders affected by the issue and result in an increase in the administrative expense of the trust in subsequent periods.
 
The trust estimates that a purchaser of trust units in this offering who owns such trust units through the record date for distributions for the period ending December 31, 2013, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately 30% of the cash distributed with respect to that period. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond the trust’s control. Further, the estimates are based on current tax law and tax reporting positions that the trust will adopt and with which the IRS could disagree. Accordingly, the trust cannot assure unitholders that these estimates will prove to be correct. The actual percentage of distributions that will correspond to taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the trust units.
 
Tax Classification of the Net Profits Interest
 
For U.S. federal income tax purposes, the Net Profits Interest attributable to proved developed reserves (“PDP NPI”) or proved undeveloped reserves (“PUD NPI”) will have the tax characteristics of mineral royalty interests to the extent, at the time of its creation, such PDP NPI or PUD NPI is reasonably expected to have an economic life that corresponds substantially to the economic life of the mineral property or properties burdened thereby. Payments out of production that are received in respect of a mineral interest that constitutes a royalty interest for U.S. federal income tax purposes are taxable under current law as ordinary income subject to an allowance for cost or percentage depletion in respect of such income.
 
Based on the reserve report and representations made by Enduro Sponsor regarding the expected economic life of the Underlying Properties and the expected duration of the Net Profits Interest, the PDP NPI will and the PUD NPI should be treated as continuing, nonoperating economic interests in the nature of royalties payable out of production from the mineral interests they burden.


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Consistent with the foregoing, Enduro Sponsor and the trust intend to treat the Net Profits Interest as a mineral royalty interest for U.S. federal income tax purposes. The remainder of this discussion assumes that the Net Profits Interest is treated as a mineral royalty interest. No assurance can be given that the IRS will not assert that such interest should be treated differently. Any such different treatment could affect the amount, timing and character of income, gain or loss in respect of an investment in trust units. Please read “— Tax Consequences to U.S. Trust Unitholders.”
 
The portion of the purchase price of the trust units attributable to the right to receive a distribution based on production from the Underlying Properties for the period commencing May 1, 2011, and ending on the closing date of this offering will be treated as a tax-free return of capital when such distribution is received.
 
Tax Consequences to U.S. Trust Unitholders
 
Royalty Income and Depletion
 
Consistent with the discussion above in “— Tax Classification of the Net Profits Interest,” the payments out of production that are received by the trust in respect of the Net Profits Interest constitute ordinary income received in respect of a mineral royalty interest. Trust unitholders should be entitled to deductions for the greater of either cost depletion or (if allowable) percentage depletion with respect to such income. Although the Code requires each trust unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying royalty interest for depletion and other purposes, the trust intends to furnish each of the trust unitholders with information relating to this computation for U.S. federal income tax purposes. Each trust unitholder, however, remains responsible for calculating his own depletion allowance and maintaining records of his share of the adjusted tax basis of the underlying property for depletion and other purposes.
 
Percentage depletion is generally available with respect to trust unitholders who qualify under the independent producer exemption contained in section 613A(c) of the Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas or derivative products or the operation of a major refinery. In general, percentage depletion is calculated as an amount equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the trust unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the trust unitholder from the property for each taxable year, computed without the depletion allowance or certain loss carrybacks. A trust unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the trust unitholder’s average daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000 barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.
 
In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a trust unitholder’s total taxable income from all sources for the year, computed without the depletion allowance and certain loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the trust unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.
 
Unlike cost depletion, percentage depletion is not limited to the adjusted tax basis of the property, although, like cost depletion, it reduces the adjusted tax basis, but not below zero.


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In addition to the limitations on percentage depletion discussed above, on February 14, 2011, the White House released President Obama’s budget proposal for the fiscal year 2012 (the “2012 Budget”). The 2012 Budget proposes to eliminate certain tax preferences applicable to taxpayers engaged in the exploration and production of natural resources. Specifically, the 2012 Budget proposes to repeal the deduction for percentage depletion with respect to oil and natural gas wells, in which case only cost depletion would be available. It is uncertain whether this or any other legislative proposals will ever be enacted and, if so, when it would become effective.
 
Trust unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the trust unitholder’s allocable share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the trust unitholder’s share of the total adjusted tax basis in the property.
 
The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the trust unitholders. Further, because depletion is required to be computed separately by each trust unitholder and not by the trust, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the trust unitholders for any taxable year. The trust encourages each prospective trust unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.
 
Tax Rates
 
Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.
 
The recently enacted Health Care and Education Reconciliation Act of 2010 will impose a 3.8% Medicare tax on certain investment income earned by individuals and certain estates and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income would generally include certain income derived from investments such as the trust units and gain realized by a trust unitholder from a sale of trust units. In the case of an individual, the tax will be imposed on the lesser of (i) the trust unitholder’s net income from all investments and (ii) the amount by which the trust unitholder’s modified adjusted gross income exceeds $250,000 (if the trust unitholder is married and filing jointly or a surviving spouse), $125,000 (if the trust unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (1) undistributed net investment income, or (2) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.
 
Non-Passive Activity Income and Loss
 
The income and losses of the trust will not be taken into account in computing the passive activity losses and income under Code section 469 for a trust unitholder who acquires and holds trust units as an investment.


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Disposition of Trust Units
 
For U.S. federal income tax purposes, a sale of trust units will be treated as a sale by the U.S. trust unitholder of his interest in the assets of the trust. Generally, a U.S. trust unitholder will recognize gain or loss on a sale or exchange of trust units equal to the difference between the amount realized and the U.S. trust unitholder’s adjusted tax basis for the trust units sold. A U.S. trust unitholder’s adjusted tax basis in his trust units will be equal to the U.S. trust unitholder’s original purchase price for the trust units, reduced by deductions for depletion claimed by the trust unitholder, but not below zero. Except to the extent of the depletion recapture amount explained below, gain or loss on the sale of trust units by a trust unitholder who is an individual will generally be capital gain, and will be long-term capital gain, which is generally subject to tax at preferential rates, if the trust units have been held for more than twelve months. The deductibility of capital losses is limited. Upon the sale or other taxable disposition of his trust units, a trust unitholder will be treated as having sold his share of the Net Profits Interest and must treat as ordinary income his depletion recapture amount, which is an amount equal to the lesser of the gain on such sale or other taxable disposition or the sum of the prior depletion deductions taken with respect to the trust units, but not in excess of the initial tax basis of the trust units. The IRS could take the position that a portion of the sales proceeds is ordinary income to the extent of any accrued income at the time of the sale that was allocable to the trust units sold even though the income is not distributed to the selling trust unitholder.
 
Trust Administrative Expenses
 
Expenses of the trust will include administrative expenses of the trustee. Certain miscellaneous itemized deductions may be subject to general limitations on deductibility. Under these rules, administrative expenses attributable to the trust units are miscellaneous itemized deductions that generally will have to be aggregated with an individual unitholder’s other miscellaneous itemized deductions to determine the excess over 2% of adjusted gross income. It is anticipated that the amount of such administrative expenses will not be significant in relation to the trust’s income.
 
Backup Withholding
 
Distributions of trust income generally will not be subject to backup withholding unless the trust unitholder is an individual or other noncorporate entity and fails to comply with specified reporting procedures.
 
Tax Treatment Upon Sale of the Net Profits Interest
 
The sale of the Net Profits Interest by the trust at or shortly after the date of dissolution of the trust will generally give rise to long-term capital gain or loss to the trust unitholders for U.S. federal income tax purposes, except that any gain will be taxed at ordinary income rates to the extent of depletion deductions that reduced the trust unitholder’s adjusted basis in the Net Profits Interest.
 
Tax Consequences to Non-U.S. Trust Unitholders
 
The following is a summary of certain material U.S. federal income tax consequences that will apply to you if you are a non-U.S. trust unitholder. Non-U.S. trust unitholders should consult their independent tax advisors to determine the U.S. federal, state, local and foreign tax consequences that may be relevant to them.
 
Payments with Respect to the Trust Units
 
A non-U.S. trust unitholder will be subject to federal withholding tax on his share of gross royalty income from the Net Profits Interest. The withholding tax will apply at a 30% rate, or lower applicable treaty rate, to the gross royalty income received by the non-U.S. trust unitholder without the benefit of any deductions.


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Sale or Exchange of Trust Units
 
The Net Profits Interest will be treated as a “United States real property interest” for U.S. federal income tax purposes. However, as long as the trust units are traded on an established securities exchange, gain realized on the sale or other taxable disposition of a trust unit by a non-U.S. trust unitholder will be subject to federal income tax only if:
 
  •      the gain is otherwise effectively connected with business conducted by the non-U.S. trust unitholder in the United States (and, in the case of an applicable tax treaty, is attributable to a permanent establishment or fixed base maintained in the United States by the non-U.S. trust unitholder);
 
  •      the non-U.S. trust unitholder is an individual who is present in the United States for at least 183 days in the year of the sale or other taxable disposition; or
 
  •      the non-U.S. trust unitholder owns currently, or owned at certain earlier times, directly, or by applying certain attribution rules, more than 5% of the trust units.
 
Gain realized by a non-U.S. trust unitholder upon the sale or other taxable disposition by the trust of all or any part of the Net Profits Interest would be subject to federal income tax, and distributions to the non-U.S. trust unitholder will be subject to withholding of U.S. tax (currently at the rate of 35%) to the extent distributions are attributable to such gains.
 
Tax Consequences to Tax Exempt Organizations
 
Employee benefit plans and most other organizations exempt from U.S. federal income tax including IRAs and other retirement plans are subject to U.S. federal income tax on unrelated business taxable income. Because the trust’s income is not expected to be unrelated business taxable income, such a tax-exempt organization is not expected to be taxed on income generated by ownership of trust units so long as neither the property held by the trust nor the trust units are treated as debt-financed property within the meaning of Section 514(b) of the Code. In general, trust property would be debt-financed if the trust incurs debt to acquire the property or otherwise incurs or maintains a debt that would not have been incurred or maintained if the property had not been acquired and a trust unit would be debt-financed if the trust unitholder incurs debt to acquire the trust unit or otherwise incurs or maintains a debt that would not have been incurred or maintained if the trust unit had not been acquired.
 
PROSPECTIVE INVESTORS IN TRUST UNITS ARE STRONGLY ENCOURAGED TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE TAX CONSEQUENCES TO THEM OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF THE TRUST UNITS IN LIGHT OF THEIR OWN PARTICULAR CIRCUMSTANCES, INCLUDING THE TAX CONSEQUENCES UNDER STATE, LOCAL, FOREIGN AND OTHER TAX LAWS AND THE POSSIBLE EFFECTS OF CHANGES IN UNITED STATES FEDERAL OR OTHER TAX LAWS.


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STATE TAX CONSIDERATIONS
 
The following is a brief summary of certain information regarding state income taxes and other state tax matters affecting individuals who are trust unitholders. No opinion of counsel has been requested or received with respect to the state tax consequences of an investment in trust units. The trust is not providing any tax advice with respect to the state tax consequences applicable to any particular purchaser of trust units. Accordingly, prospective investors are urged to consult their tax advisors with respect to these matters.
 
The trust will own net profits interests burdening specified oil and natural gas properties located in the states of Louisiana, New Mexico and Texas. Louisiana and New Mexico currently impose a personal income tax on individuals, but Texas currently does not.
 
An individual who is a resident of Louisiana or New Mexico will generally be subject to income tax in his or her state of residence on that individual’s entire share of the trust’s income.
 
New Mexico imposes income taxes upon residents and nonresidents. In the case of nonresidents, income derived from tangible property within the state is subject to tax. The income tax laws of New Mexico are based on federal income tax laws. Thus, assuming the trust is taxed as a grantor trust for federal income tax purposes, the trust unitholders will be subject to New Mexico income tax on their share of income from New Mexico net profits interests. The withholding requirements with respect to trust units under New Mexico law are uncertain; the trust has taken the position that the trust is not required to withhold income tax in New Mexico on distributions made to an individual resident or nonresident trust unitholder.
 
Louisiana also imposes income taxes upon residents and nonresidents. In the case of nonresidents, income derived from property within the state is subject to tax. The income tax laws of Louisiana are based on federal income tax laws. Assuming the trust is taxed as a grantor trust for federal income tax purposes, the trust unitholders will be subject to Louisiana income tax on their share of income from Louisiana net profits interests. The trust should not be required to withhold income tax due in Louisiana on distributions made to an individual resident or nonresident trust unitholder.


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ERISA CONSIDERATIONS
 
The Employee Retirement Income Security Act of 1974, as amended (“ERISA”), regulates pension, profit-sharing and other employee benefit plans to which it applies. ERISA also contains standards for persons who are fiduciaries of those plans. In addition, the Code provides similar requirements and standards which are applicable to qualified plans, which include these types of plans, and to individual retirement accounts, whether or not subject to ERISA.
 
A fiduciary of an employee benefit plan should carefully consider fiduciary standards under ERISA regarding the plan’s particular circumstances before authorizing an investment in trust units. A fiduciary should consider:
 
  •      whether the investment satisfies the prudence requirements of Section 404(a)(1)(B) of ERISA;
 
  •      whether the investment satisfies the diversification requirements of Section 404(a)(1)(C) of ERISA; and
 
  •      whether the investment is in accordance with the documents and instruments governing the plan as required by Section 404(a)(1)(D) of ERISA.
 
A fiduciary should also consider whether an investment in trust units might result in direct or indirect nonexempt prohibited transactions under Section 406 of ERISA and Section 4975 of the Code. In deciding whether an investment involves a prohibited transaction, a fiduciary must determine whether there are plan assets in the transaction. The Department of Labor has published final regulations concerning whether or not an employee benefit plan’s assets would be deemed to include an interest in the underlying assets of an entity for purposes of the reporting, disclosure and fiduciary responsibility provisions of ERISA and analogous provisions of the Code. These regulations provide that the underlying assets of an entity will not be considered “plan assets” if the equity interests in the entity are a publicly offered security. Enduro Sponsor expects that at the time of the sale of the trust units in this offering, they will be publicly offered securities. Fiduciaries, however, will need to determine whether the acquisition of trust units is a nonexempt prohibited transaction under the general requirements of ERISA Section 406 and Section 4975 of the Code.
 
The prohibited transaction rules are complex, and persons involved in prohibited transactions are subject to penalties. For that reason, potential employee benefit plan investors should consult with their counsel to determine the consequences under ERISA and the Code of their acquisition and ownership of trust units.


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SELLING TRUST UNITHOLDER
 
Immediately prior to the closing of the offering made hereby, Enduro Sponsor will convey, or cause to be conveyed, to the trust the Net Profits Interest in exchange for 33,000,000 trust units. Of those trust units, 13,200,000 are being offered hereby and 1,980,000 are subject to purchase by the underwriters pursuant to their 30-day option to purchase additional trust units. Enduro Sponsor has agreed not to sell any of such trust units for a period of 180 days after the date of this prospectus without the prior written consent of Barclays Capital Inc., acting as representative of the several underwriters. See “Underwriting (Conflicts of Interest).” Enduro Sponsor is deemed to be an underwriter with respect to the trust units offered hereby.
 
The following table provides information regarding the selling trust unitholder’s ownership of the trust units.
 
                                         
    Ownership of Trust
  Number of
  Ownership of Trust Units After
    Units Before Offering   Trust Units
  Offering(1)
Selling Trust Unitholder
  Number   Percentage   Being Offered   Number   Percentage
 
Enduro Sponsor
    33,000,000       100.0 %     15,180,000 (2)     19,800,000       60 %
 
 
(1) Assumes the underwriters do not exercise their 30-day option to purchase additional units.
 
(2) Includes 1,980,000 trust units subject to purchase by the underwriters pursuant to their 30-day option to purchase additional units.
 
Prior to this offering, there has been no public market for the trust units. Therefore, if Enduro Sponsor disposes of all or a portion of the trust units it has acquired, the effect of such disposal on future market prices, if any, of market sales of such remaining trust units or the availability of trust units for sale cannot be predicted. Nevertheless, sales of substantial amounts of trust units in the public market could adversely affect future market prices.


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UNDERWRITING (CONFLICTS OF INTEREST)
 
Barclays Capital Inc., Citigroup Global Markets Inc., Goldman, Sachs & Co., RBC Capital Markets, LLC and Wells Fargo Securities, LLC are acting as the representatives of the underwriters of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from Enduro Sponsor the respective number of trust units shown opposite its name below:
 
         
    Number of
 
Underwriters
  Trust Units  
 
Barclays Capital Inc. 
       
Citigroup Global Markets Inc. 
       
Goldman, Sachs & Co. 
       
RBC Capital Markets, LLC
       
Wells Fargo Securities, LLC
       
J.P. Morgan Securities LLC
       
Robert W. Baird & Co. Incorporated
       
Morgan Keegan & Co., Inc. 
       
Stifel, Nicolaus & Company, Incorporated
       
Wunderlich Securities, Inc. 
       
         
Total
    13,200,000  
         
 
The underwriting agreement provides that the underwriters’ obligation to purchase trust units depends on the satisfaction of the conditions contained in the underwriting agreement including:
 
  •      the obligation to purchase all of the trust units offered hereby (other than those trust units covered by their option to purchase additional trust units as described below), if any of the trust units are purchased;
 
  •      the representations and warranties made by the trust and Enduro Sponsor to the underwriters are true;
 
  •      there is no material change in the business of the trust or Enduro Sponsor or the financial markets; and
 
  •      the trust and Enduro Sponsor deliver customary closing documents to the underwriters.
 
Enduro Sponsor is deemed to be an underwriter with respect to the trust units offered hereby.
 
Commissions and Expenses
 
The following table summarizes the underwriting discounts and commissions Enduro Sponsor will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional trust units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to Enduro Sponsor for the trust units.
 
         
   
No Exercise
 
Full Exercise
 
Per trust unit
       
Total
       
 
The representatives of the underwriters have advised Enduro Sponsor that the underwriters propose to offer the trust units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $      per trust unit. After the offering, the representatives may change the offering price and other selling terms.


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The offering of the trust units by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.
 
Enduro Sponsor will pay Barclays Capital Inc. a structuring fee of 0.5% of the gross proceeds of this offering for evaluation, analysis and structuring of the trust.
 
The expenses of the offering that are payable by Enduro Sponsor are estimated to be $4.0 million (excluding underwriting discounts and commissions).
 
Option to Purchase Additional Trust Units
 
Enduro Sponsor has granted the underwriters an option exercisable for 30 days after the date of this prospectus, to purchase, from time to time, in whole or in part, up to an aggregate of 1,980,000 trust units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than 13,200,000 trust units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional trust units based on the underwriter’s underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting Section.
 
Lock-Up Agreements
 
Enduro Sponsor has agreed that, without the prior written consent of Barclays Capital Inc., they will not directly or indirectly, (1) offer for sale, sell, pledge or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any trust units (including, without limitation, trust units that may be deemed to be beneficially owned by them in accordance with the rules and regulations of the SEC and trust units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for trust units or sell or grant options, rights or warrants with respect to any trust units or securities convertible into or exchangeable for trust units (other than the sale of the trust units to the underwriters in this offering), (2) enter into any swap or other derivative transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the trust units, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any trust units or securities convertible, exercisable or exchangeable into trust units or any other securities of the trust or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.
 
The 180-day restricted period described in the preceding paragraph will be extended if:
 
  •      during the last 17 days of the 180-day restricted period the trust issues an earnings release or material news or a material event relating to the trust occurs; or
 
  •      prior to the expiration of the 180-day restricted period, the trust announces that it will release earnings results during the 16-day period beginning on the last day of the 180-day period,
 
in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or occurrence of a material event, unless such extension is waived in writing by Barclays Capital Inc.
 
Barclays Capital Inc., in its sole discretion, may release the trust units and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release trust units and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of trust units and other securities for which the release is being requested and


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market conditions at the time. Barclays Capital Inc. has informed Enduro Sponsor that it does not presently intend to release any trust units or other securities subject to the lock-up agreements.
 
As described below under “Directed Unit Program,” any participants in the directed unit program will be subject to a 180-day lock up with respect to any trust units sold to them pursuant to that program. This lock up will have similar restrictions and an identical extension provision as the lock-up agreement described above. Any trust units sold in the directed unit program to Enduro Sponsor’s directors or officers will be subject to the lock-up agreement described above.
 
Offering Price Determination
 
Prior to this offering, there has been no public market for the trust units. The initial public offering price will be negotiated between the representatives and Enduro Sponsor. In determining the initial public offering price of the trust units, the representatives will consider:
 
  •      estimates of distributions to trust unitholders;
 
  •      overall quality of the oil and natural gas properties attributable to the Underlying Properties;
 
  •      the history and prospects for the energy industry;
 
  •      Enduro Sponsor’s financial information;
 
  •      the prevailing securities markets at the time of this offering; and
 
  •      the recent market prices of, and the demand for, publicly traded units of royalty trusts.
 
Indemnification
 
The trust and Enduro Sponsor have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act and liabilities incurred in connection with the directed unit program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities.
 
Directed Unit Program
 
At Enduro Sponsor’s request, the underwriters have reserved for sale at the initial public offering price up to 660,000 trust units offered hereby for officers, managers, employees and certain other persons associated with Enduro Sponsor. The number of trust units available for sale to the general public will be reduced to the extent such persons purchase such reserved trust units. Any reserved trust units not so purchased will be offered by the underwriters to the general public on the same basis as the other trust units offered hereby. Any of Enduro Sponsor’s officers or managers participating in this program shall be prohibited from selling, pledging or assigning any trust units sold to them pursuant to this program for a period of 180 days after the date of this prospectus. Individuals (other than Enduro Sponsor’s officers and managers) who purchase trust units in the directed unit program will be subject to a 25-day lock-up period. These lock up periods will be extended with respect to the trust’s issuance of an earnings release or if a material news or a material event relating to the trust occurs, in the same manner as described above under “— Lock-Up Agreements.”
 
Stabilization, Short Positions and Penalty Bids
 
The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the trust units, in accordance with Regulation M under the Exchange Act:
 
  •      Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.


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  •      A short position involves a sale by the underwriters of trust units in excess of the number of trust units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of trust units involved in the sales made by the underwriters in excess of the number of trust units they are obligated to purchase is not greater than the number of trust units that they may purchase by exercising their option to purchase additional trust units. In a naked short position, the number of trust units involved is greater than the number of trust units in their option to purchase additional trust units. The underwriters may close out any short position by either exercising their option to purchase additional trust units and/or purchasing trust units in the open market. In determining the source of trust units to close out the short position, the underwriters will consider, among other things, the price of trust units available for purchase in the open market as compared to the price at which they may purchase trust units through their option to purchase additional trust units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the trust units in the open market after pricing that could adversely affect investors who purchase in the offering.
 
  •      Syndicate covering transactions involve purchases of the trust units in the open market after the distribution has been completed in order to cover syndicate short positions.
 
  •      Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the trust units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.
 
These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of the trust units or preventing or retarding a decline in the market price of the trust units. As a result, the price of the trust units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.
 
None of the trust, Enduro Sponsor or any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the trust units. In addition, none of the trust, Enduro Sponsor or any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.
 
Electronic Distribution
 
A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with Enduro Sponsor to allocate a specific number of trust units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.
 
Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by the trust, Enduro Sponsor or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.


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New York Stock Exchange
 
The trust units have been approved for listing on the New York Stock Exchange, subject to official notice of issuance, under the symbol “NDRO.” In connection with that listing, the underwriters have undertaken to sell the minimum number of trust units to the minimum number of beneficial owners necessary to meet the New York Stock Exchange listing requirements.
 
Discretionary Sales
 
The underwriters have informed Enduro Sponsor that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of trust units offered by them.
 
Conflicts of Interest/FINRA Rules
 
The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. Certain of the underwriters and their respective affiliates have, from time to time, performed, and may in the future perform, various financial advisory and investment banking services for Enduro Sponsor and the trust, for which they received or will receive customary fees and expenses.
 
Because the Financial Industry Regulatory Authority (“FINRA”) views the trust units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2310 of the FINRA Conduct Rules. In no event will the maximum amount of compensation to be paid to FINRA members in connection with this offering exceed 10% of the offering proceeds. Investor suitability with respect to the trust units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.
 
In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and/or instruments of Enduro Sponsor and the trust. The underwriters and their respective affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments. Additionally, affiliates of RBC Capital Markets, LLC and Wells Fargo Securities, LLC are lenders under Enduro Sponsor’s senior secured credit agreement and will receive a substantial portion of the proceeds from this offering pursuant to the repayment of a portion of the borrowings thereunder.


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LEGAL MATTERS
 
Richards, Layton & Finger, P.A., as special Delaware counsel to the trust, will give a legal opinion as to the validity of the trust units. Latham & Watkins LLP, Houston, Texas, will give opinions as to certain other matters relating to the offering, including the tax opinion described in the section of this prospectus captioned “Federal Income Tax Consequences.” Certain legal matters in connection with the trust units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas. Baker Botts L.L.P. performs legal services for Enduro Sponsor and its affiliates from time to time on matters unrelated to this offering.
 
EXPERTS
 
Certain information appearing in this registration statement regarding the December 31, 2010 estimated quantities of reserves of Enduro Sponsor, the Underlying Properties and the Net Profits Interest owned by the trust, the future net revenues from those reserves and their present value is based on estimates of the reserves and present values prepared by or derived from estimates prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers.
 
The audited financial statements included in this prospectus and registration statement as listed on the index to financial statements on page F-1 and the index to financial statements of Enduro Sponsor on page ENDURO F-1 have been audited by Ernst & Young, LLP, independent registered public accounting firm, as set forth in their reports thereon appearing elsewhere herein, and are included in reliance upon such reports given upon the authority of such firm as experts in accounting and auditing.
 
WHERE YOU CAN FIND MORE INFORMATION
 
The trust and Enduro Sponsor have filed with the SEC in Washington, D.C. a registration statement, including all amendments, under the Securities Act relating to the trust units. As permitted by the rules and regulations of the SEC, this prospectus does not contain all of the information contained in the registration statement and the exhibits and schedules to the registration statement. You may read and copy the registration statement at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at the address in the previous sentence. To obtain information on the operation of the public reference room you may call the SEC at (800) SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. The trust’s and Enduro Sponsor’s registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.
 
The trustee intends to furnish the trust unitholders with annual reports containing the trust’s audited consolidated financial statements and to furnish or make available to the trust unitholders quarterly reports containing the trust’s unaudited interim financial information for the first three fiscal quarters of each of the trust’s fiscal years.


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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS
 
In this prospectus the following terms have the meanings specified below.
 
Bbl — One stock tank barrel of 42 U.S. gallons liquid volume, used herein in reference to crude oil and other liquid hydrocarbons.
 
Boe — One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals six Mcf of natural gas.
 
Btu — A British Thermal Unit, a common unit of energy measurement.
 
Completion — The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
 
Development Well — A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
 
Differential — The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot, and the wellhead price received.
 
Estimated future net revenues — Also referred to as “estimated future net cash flows.” The result of applying current prices of oil and natural gas to estimated future production from oil and natural gas proved reserves, reduced by estimated future expenditures, based on current costs to be incurred, in developing and producing the proved reserves, excluding overhead.
 
Farm-in or farm-out agreement — An agreement under which the owner of a working interest in an oil or natural gas lease typically assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”
 
Field — An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
 
Gross acres or gross wells — The total acres or wells, as the case may be, in which a working interest is owned.
 
Horizontal well — A well that starts off being drilled vertically but which is eventually curved to become horizontal (or near horizontal) in order to parallel a particular geologic formation.
 
MBbl — One thousand barrels of crude oil or condensate.
 
MBoe — One thousand barrels of oil equivalent.
 
Mcf — One thousand cubic feet of natural gas.
 
MMBoe — One million barrels of oil equivalent.
 
MMBtu — One million British Thermal Units.
 
MMcf — One million cubic feet of natural gas.
 
Net acres or net wells — The sum of the fractional working interests owned in gross acres or wells, as the case may be.
 
Net profits interest — A nonoperating interest that creates a share in gross production from an operating or working interest in oil and natural gas properties. The share is measured by net profits from the sale of production after deducting costs associated with that production.


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Net revenue interest — An interest in all oil and natural gas produced and saved from, or attributable to, a particular property, net of all royalties, overriding royalties, net profits interests, carried interests, reversionary interests and any other burdens to which the person’s interest is subject.
 
Plugging and abandonment — Activities to remove production equipment and seal off a well at the end of a well’s economic life.
 
Proved developed reserves — Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
 
Proved reserves — Under SEC rules for fiscal years ending on or after December 31, 2009, proved reserves are defined as:
 
Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
 
Under SEC rules for fiscal years ending prior to December 31, 2009, proved reserves are defined as:
 
The estimated quantities of crude oil and natural gas, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural


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occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. Estimates of proved reserves do not include the following: (A) Oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil and natural gas, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil and natural gas, that may occur in undrilled prospects; and (D) crude oil and natural gas, that may be recovered from oil shales, coal, gilsonite and other such sources.
 
Proved undeveloped reserves — Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
 
PV-10 — The present value of estimated future net revenues using a discount rate of 10% per annum.
 
Recompletion — The completion for production of an existing well bore in another formation from which that well has been previously completed.
 
Reservoir — A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
 
Working interest — The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
 
Workover — Operations on a producing well to restore or increase production.


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INDEX TO FINANCIAL STATEMENTS
 
         
PREDECESSOR UNDERLYING PROPERTIES:
       
    F-2  
    F-3  
    F-4  
    F-5  
    F-6  
SAMSON PERMIAN BASIN ASSETS:
       
    F-11  
    F-12  
    F-13  
    F-14  
    F-15  
CONOCOPHILLIPS PERMIAN BASIN ASSETS:
       
    F-19  
    F-20  
    F-21  
    F-22  
    F-23  
UNAUDITED PRO FORMA COMBINED UNDERLYING PROPERTIES:
       
    F-27  
    F-28  
ENDURO ROYALTY TRUST:
       
    F-31  
    F-32  
    F-33  
Unaudited Pro Forma Financial Statements:
       
    F-35  
    F-36  
    F-37  
    F-38  
 
The audited financial statements of the Predecessor can be found beginning on
page ENDURO F-1.


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PREDECESSOR UNDERLYING PROPERTIES
 
UNAUDITED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
 
                 
    Three Months Ended March 31,  
    2011     2010  
    (In thousands)  
 
Revenues:
               
Oil
  $ 335     $ 433  
Natural gas
    4,477       6,632  
                 
Total revenues
    4,812       7,065  
                 
Direct operating expenses:
               
Lease operating
    1,238       1,118  
Gathering and processing
    386       307  
Production and other taxes
    243       426  
                 
Total direct operating expenses
    1,867       1,851  
                 
Excess of revenues over direct operating expenses
  $ 2,945     $ 5,214  
                 
 
The accompanying notes are an integral part of these statements.


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PREDECESSOR UNDERLYING PROPERTIES
 
NOTES TO UNAUDITED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
 
1.   Basis of Presentation
 
On December 1, 2010 (the “Acquisition Date”), Enduro Resource Partners LLC (“Enduro”) completed the acquisition of certain oil and natural gas properties located in East Texas and North Louisiana from Denbury Resources Inc. (“Denbury”) for a cash purchase price of approximately $217.4 million. These assets were acquired by Denbury on March 9, 2010 in connection with Denbury’s acquisition of Encore Acquisition Company (“Encore”). The portion of these properties Enduro expects to contribute to Enduro Royalty Trust are collectively referred to herein as the “Predecessor Underlying Properties.”
 
The accompanying unaudited statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of Enduro for periods subsequent to the Acquisition Date and of Denbury and Encore for their respective ownership periods prior to the Acquisition Date.
 
During the periods presented, the Predecessor Underlying Properties were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying unaudited statements of revenues and direct operating expenses are not indicative of the financial condition or results of operations of the Predecessor Underlying Properties and such amounts may not be representative of future operations.
 
These unaudited statements of revenues and direct operating expenses do not represent a complete set of financial statements reflecting the financial position, results of operations, shareholders’ equity, and cash flows of the Predecessor Underlying Properties. In the opinion of management, the accompanying unaudited statements of revenues and direct operating expenses include all adjustments considered necessary for fair presentation on the basis described above. All adjustments are of a normal recurring nature.
 
2.   Contingencies
 
The activities of the Predecessor Underlying Properties are subject to potential claims and litigation in the normal course of operations. Enduro’s management does not believe that any liability resulting from any pending or threatened litigation will have a material adverse effect on the operations or financial results of the Predecessor Underlying Properties.
 
3.   Cash Flow Information
 
Capital expenditures relating to the Predecessor Underlying Properties were approximately $6.1 million and $1.5 million for the three months ended March 31, 2011 and 2010, respectively. Other cash flow information is not available on a stand-alone basis for the Predecessor Underlying Properties.
 
4.   Subsequent Events
 
Subsequent events have been evaluated through July 1, 2011, the date the statements were available to be issued, to ensure that any subsequent events that met the criteria for recognition or disclosure in this report have been included. No subsequent events requiring recognition or disclosure have occurred.


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Table of Contents

 
Report of Independent Registered Public Accounting Firm
 
To the Board of Managers and Members of Enduro Resource Partners LLC:
 
We have audited the accompanying statements of revenues and direct operating expenses of the Predecessor Underlying Properties, described in Note 1, for the years ended December 31, 2010, 2009 and 2008. These statements are the responsibility of Enduro Resource Partners LLC’s management. Our responsibility is to express an opinion on these statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements are free of material misstatement. We were not engaged to perform an audit of the internal controls over financial reporting of the revenues and direct operating expenses of the Predecessor Underlying Properties. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate for the circumstances, but not for the purpose of expressing an opinion on the effectiveness of internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statements. We believe that our audits provide a reasonable basis for our opinion.
 
The accompanying statements reflect the revenues and direct operating expenses of the Predecessor Underlying Properties, as described in Note 1, and are not intended to be a complete presentation of the Predecessor Underlying Properties’ revenues and expenses.
 
In our opinion, the statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Predecessor Underlying Properties for the years ended December 31, 2010, 2009 and 2008 in conformity with U.S. generally accepted accounting principles.
 
/s/  Ernst & Young LLP
 
Fort Worth, Texas
May 11, 2011


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PREDECESSOR UNDERLYING PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands)  
 
Revenues:
                       
Oil
  $ 1,345     $ 1,685     $ 3,057  
Natural gas
    21,112       22,519       54,485  
                         
Total revenues
    22,457       24,204       57,542  
                         
Direct operating expenses:
                       
Lease operating
    4,484       5,365       4,695  
Gathering and processing
    1,522       1,474       2,471  
Production and other taxes
    1,373       1,965       2,259  
                         
Total direct operating expenses
    7,379       8,804       9,425  
                         
Excess of revenues over direct operating expenses
  $ 15,078     $ 15,400     $ 48,117  
                         
 
The accompanying notes are an integral part of these statements.


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Table of Contents

PREDECESSOR UNDERLYING PROPERTIES
 
 
1.   Basis of Presentation
 
On December 1, 2010 (the “Acquisition Date”), Enduro Resource Partners LLC (“Enduro”) completed the acquisition of certain oil and natural gas properties located in East Texas and North Louisiana from Denbury Resources Inc. (“Denbury”) for a cash purchase price of approximately $213.8 million, subject to post-closing adjustments. These assets were acquired by Denbury on March 9, 2010 in connection with Denbury’s acquisition of Encore Acquisition Company (“Encore”). The portion of these properties Enduro expects to contribute to Enduro Royalty Trust are collectively referred to herein as the “Predecessor Underlying Properties.”
 
The accompanying statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of Enduro for periods subsequent to the Acquisition Date and of Denbury and Encore for their respective ownership periods prior to the Acquisition Date.
 
During the periods presented, the Predecessor Underlying Properties were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying statements of revenues and direct operating expenses are not indicative of the financial condition or results of operations of the Predecessor Underlying Properties and such amounts may not be representative of future operations.
 
Full separate financial statements prepared in accordance with generally accepted accounting principles are not presented as the information necessary to prepare such statements is neither readily available on an individual property basis nor practicable to obtain in these circumstances. Accordingly, the statements of revenues and direct operating expenses of the Predecessor Underlying Properties are presented in lieu of the financial statements otherwise required under Rules 3-01 and 3-02 of Regulation S-X by the Securities and Exchange Commission (“SEC”).
 
2.   Significant Accounting Policies
 
(a)   Use of Estimates
 
Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the statements of revenues and direct operating expenses. Actual balances and results could be different from those estimates.
 
(b)   Revenue Recognition
 
Oil and natural gas revenues are recognized when such products have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibilities of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Revenues are reported net of royalties and other amounts due to third parties.
 
(c)   Direct Operating Expenses
 
Direct operating expenses are recognized when incurred and consist of the direct expenses of operating the Predecessor Underlying Properties. Direct operating expenses include lease operating,


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PREDECESSOR UNDERLYING PROPERTIES
 
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
 
gathering, processing, and production and other tax expenses. Lease operating expenses include the costs of maintaining and operating property and equipment on producing oil and natural gas leases and include field labor, insurance, maintenance, repairs, utilities and supplies, and well workover and field expenses. Gathering and processing expenses include the costs of oil and/or natural gas taken in-kind for the use of gas processing facilities as well as maintenance, repair, and other operating costs incurred in gathering the production. Production and other taxes consist of severance and ad valorem taxes. Production taxes are recorded at the time transfer of title occurs. Such taxes represent a fixed percentage of production and are calculated and paid to the state governments in accordance with applicable regulations.
 
3.   Contingencies
 
The activities of the Predecessor Underlying Properties are subject to potential claims and litigation in the normal course of operations. Enduro’s management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the Predecessor Underlying Properties.
 
4.   Cash Flow Information
 
Capital expenditures relating to the Predecessor Underlying Properties were approximately $7.8 million, $16.9 million, and $53.7 million for the years ended December 31, 2010, 2009, and 2008, respectively. Other cash flow information is not available on a stand-alone basis for the Predecessor Underlying Properties.
 
5.   Subsequent Events
 
Subsequent events have been evaluated through May 11, 2011, the date the statements were available to be issued, to ensure that any subsequent events that met the criteria for recognition or disclosure in this report have been included. No subsequent events requiring recognition or disclosure have occurred.
 
6.   Supplemental Oil and Natural Gas Disclosures (Unaudited)
 
The following unaudited supplemental oil and natural gas disclosures were derived from reserve reports which were prepared by Enduro’s, Denbury’s and Encore’s reserve engineers and are presented in accordance with the Financial Accounting Standards Board ASC Topic 932, Extractive Activities — Oil and Gas (“ASC 932”). The unaudited supplemental information reflects the revised oil and natural gas reserve estimation and disclosure requirements of the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC in 2008 and were effective December 31, 2009. The following unaudited supplemental information for 2010 and 2009 has been presented in accordance with the revised reserve estimation and disclosure rules, which were not applied retrospectively. Accordingly, the information for 2008 is presented in accordance with the oil and gas disclosure requirements effective during that period.
 
Oil and Natural Gas Reserve Quantities
 
Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing, and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating


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PREDECESSOR UNDERLYING PROPERTIES
 
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
 
costs. The process of estimating quantities of oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reserve. Consequently, material revisions to existing reserve estimates may occur from time to time.
 
The following table presents the estimated remaining net proved and proved developed oil and natural gas reserves of the Predecessor Underlying Properties and changes therein, for the periods indicated.
 
                         
    Oil
    Natural Gas
    Total
 
    (MBbls)     (MMcf)     (MBOE)  
 
January 1, 2008
    114       38,126       6,468  
Revisions of previous estimates
    70       26,511       4,489  
Production
    (33 )     (6,449 )     (1,108 )
                         
December 31, 2008
    151       58,188       9,849  
Revisions of previous estimates
    (16 )     2,490       399  
Production
    (31 )     (6,069 )     (1,043 )
                         
December 31, 2009
    104       54,609       9,205  
Revisions of previous estimates
    (61 )     14,673       2,385  
Production
    (18 )     (4,976 )     (847 )
                         
December 31, 2010
    25       64,306       10,743  
                         
Proved developed reserves as of:
                       
December 31, 2008
    106       43,480       7,353  
December 31, 2009
    59       35,497       5,975  
December 31, 2010
    25       31,105       5,209  
Proved undeveloped reserves as of:
                       
December 31, 2008
    45       14,708       2,496  
December 31, 2009
    45       19,112       3,230  
December 31, 2010
          33,201       5,534  
 
Standardized Measure of Discounted Future Net Cash Flows
 
Estimated discounted future net cash flows and changes therein were determined for the Predecessor Underlying Properties in accordance with ASC 932. Future cash inflows for 2010 and 2009 were computed by applying the average prices of oil and natural gas during the 12-month period to the period-end quantities of those proved reserves (with consideration of price changes only to the extent provided by contractual arrangements). The average prices were determined using the arithmetic average of the prices in effect on the first day of the month for each month within the period. This same 12-month average price was also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. Future cash inflows for 2008 were computed by using the year-end oil and natural gas prices in accordance with the disclosure requirements effective during that period.


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PREDECESSOR UNDERLYING PROPERTIES
 
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
 
The prices per unit used for the Predecessor Underlying Properties’ proved reserves and future net revenues are as follows:
 
                         
    December 31,  
    2010     2009     2008  
 
Oil (per Bbl)
  $ 79.43     $ 61.18     $ 44.60  
Natural gas (per Mcf)
  $ 4.37     $ 3.83     $ 5.62  
 
Future development and production costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves based on period-end costs assuming continuation of existing economic conditions. No future income tax expense was computed as taxable income arising from the operations of the properties accrues to the owner. An annual discount rate of 10% was used to reflect the timing of the future net cash flows.
 
Discounted future cash flow estimates like those shown below are not intended to present, nor should they be interpreted to present, the fair value of the Predecessor Underlying Properties’ oil and natural gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future commodity prices, interest rates, changes in development and production costs, and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.
 
The following table presents the estimates of the standardized measure of discounted future net cash flows from proved reserves of oil and natural gas for the periods indicated.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands)  
 
Future cash inflows
  $ 263,643     $ 200,931     $ 311,799  
Future production costs
    (62,667 )     (75,873 )     (94,767 )
Future development costs
    (51,674 )     (37,531 )     (39,163 )
                         
Future net cash flows
    149,302       87,527       177,869  
10% discount for estimating timing of cash flows
    (79,745 )     (41,852 )     (81,788 )
                         
Standardized measure of discounted future net cash flows
  $ 69,557     $ 45,675     $ 96,081  
                         


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Table of Contents

PREDECESSOR UNDERLYING PROPERTIES
 
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
 
The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the periods indicated.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
          (In thousands)        
 
Sales of oil and natural gas produced, net of production costs
  $ (15,078 )   $ (15,400 )   $ (48,117 )
Net changes in prices and production costs
    24,282       (44,320 )     (27,554 )
Revisions of previous quantity estimates
    23,286       2,930       53,925  
Development costs incurred during the period
    7,779       16,926       26,841  
Accretion of discount
    4,567       9,608       9,827  
Change in estimated future development costs
    (17,147 )     (11,963 )     (30,633 )
Timing and other
    (3,807 )     (8,187 )     13,527  
                         
Net change in standardized measure
    23,882       (50,406 )     (2,184 )
Standardized measure, beginning of year
    45,675       96,081       98,265  
                         
Standardized measure, end of year
  $ 69,557     $ 45,675     $ 96,081  
                         
                         


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SAMSON PERMIAN BASIN ASSETS
 
UNAUDITED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
 
                 
    Three Months Ended March 31,  
    2011     2010  
    (In thousands)  
 
Revenues:
               
Oil
  $ 4,351     $ 4,289  
Natural gas
    1,213       1,680  
                 
Total revenues
    5,564       5,969  
                 
Direct operating expenses:
               
Lease operating
    785       919  
Gathering and processing
    56       56  
Production and other taxes
    377       441  
                 
Total direct operating expenses
    1,218       1,416  
                 
Excess of revenues over direct operating expenses
  $ 4,346     $ 4,553  
                 
 
The accompanying notes are an integral part of these statements.


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SAMSON PERMIAN BASIN ASSETS
 
NOTES TO UNAUDITED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
 
1.   Basis of Presentation
 
On January 5, 2011 (the “Acquisition Date”), Enduro Resource Partners LLC (“Enduro”) completed the acquisition of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico (the “Samson Permian Basin Assets”) from Samson Investment Company and related subsidiaries (collectively, “Samson”) for a cash purchase price of approximately $133.8 million, subject to post-closing adjustments.
 
The accompanying unaudited statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of Enduro for periods subsequent to the Acquisition Date and of Samson for periods prior to the Acquisition Date.
 
During the periods presented, the Samson Permian Basin Assets were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying unaudited statements of revenues and direct operating expenses are not indicative of the financial condition or results of operations of the Samson Permian Basin Assets and such amounts may not be representative of future operations.
 
These unaudited statements of revenues and direct operating expenses do not represent a complete set of financial statements reflecting the financial position, results of operations, shareholders’ equity, and cash flows of the Samson Permian Basin Assets. In the opinion of management, the accompanying unaudited statements of revenues and direct operating expenses include all adjustments considered necessary for fair presentation on the basis described above. All adjustments are of a normal recurring nature.
 
2.   Contingencies
 
The activities of the Samson Permian Basin Assets are subject to potential claims and litigation in the normal course of operations. Enduro’s management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the Samson Permian Basin Assets.
 
3.   Cash Flow Information
 
Capital expenditures relating to the Samson Permian Basin Assets were approximately $5,000 and $92,000 for the three months ended March 31, 2011 and 2010, respectively. Other cash flow information is not available on a stand-alone basis for the Samson Permian Basin Assets.
 
4.   Subsequent Events
 
Subsequent events have been evaluated through July 1, 2011, the date the statements were available to be issued, to ensure that any subsequent events that met the criteria for recognition or disclosure in this report have been included. No subsequent events requiring recognition or disclosure have occurred.


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Report of Independent Registered Public Accounting Firm
 
To the Board of Managers and Members of Enduro Resource Partners LLC:
 
We have audited the accompanying statements of revenues and direct operating expenses of the Samson Permian Basin Assets, described in Note 1, for the years ended December 31, 2010, 2009 and 2008. These statements are the responsibility of Enduro Resource Partners LLC’s management. Our responsibility is to express an opinion on these statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements are free of material misstatement. We were not engaged to perform an audit of the internal controls over financial reporting of the revenues and direct operating expenses of the Samson Permian Basin Assets. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate for the circumstances, but not for the purpose of expressing an opinion on the effectiveness of internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statements. We believe that our audits provide a reasonable basis for our opinion.
 
The accompanying statements reflect the revenues and direct operating expenses of the Samson Permian Basin Assets, as described in Note 1, and are not intended to be a complete presentation of the Samson Permian Basin Assets’ revenues and expenses.
 
In our opinion, the statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Samson Permian Basin Assets for the years ended December 31, 2010, 2009 and 2008 in conformity with U.S. generally accepted accounting principles.
 
/s/  Ernst & Young LLP
 
Tulsa, Oklahoma
May 9, 2011


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SAMSON PERMIAN BASIN ASSETS
 
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands)  
 
Revenues:
                       
Oil
  $ 16,626     $ 13,174     $ 23,730  
Natural gas
    5,650       4,733       9,770  
                         
Total revenues
    22,276       17,907       33,500  
                         
Direct operating expenses:
                       
Lease operating
    3,438       3,783       4,327  
Gathering and processing
    212       177       178  
Production and other taxes
    1,702       1,558       2,549  
                         
Total direct operating expenses
    5,352       5,518       7,054  
                         
Excess of revenues over direct operating expenses
  $ 16,924     $ 12,389     $ 26,446  
                         
 
The accompanying notes are an integral part of these statements.


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SAMSON PERMIAN BASIN ASSETS
 
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
 
1.   Basis of Presentation
 
On January 5, 2011 (the “Acquisition Date”), Enduro Resource Partners LLC (“Enduro”) completed the acquisition of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico (the “Samson Permian Basin Assets”) from Samson Investment Company and related subsidiaries (collectively, “Samson”) for a cash purchase price of approximately $133.8 million, subject to post-closing adjustments.
 
The accompanying statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of Enduro for periods subsequent to the Acquisition Date and of Samson for periods prior to the Acquisition Date.
 
During the periods presented, the Samson Permian Basin Assets were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying statements of revenues and direct operating expenses are not indicative of the financial condition or results of operations of the Samson Permian Basin Assets and such amounts may not be representative of future operations.
 
Full separate financial statements prepared in accordance with generally accepted accounting principles are not presented as the information necessary to prepare such statements is neither readily available on an individual property basis nor practicable to obtain in these circumstances. Accordingly, the statements of revenues and direct operating expenses of the Samson Permian Basin Assets are presented in lieu of the financial statements otherwise required under Rules 3-01 and 3-02 of Regulation S-X by the Securities and Exchange Commission (“SEC”).
 
2.   Significant Accounting Policies
 
(a)   Use of Estimates
 
Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the statements of revenues and direct operating expenses. Actual balances and results could be different from those estimates.
 
(b)   Revenue Recognition
 
Oil and natural gas revenues are recognized when such products have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibilities of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Revenues are reported net of royalties and other amounts due to third parties.
 
(c)   Direct Operating Expenses
 
Direct operating expenses are recognized when incurred and consist of the direct expenses of operating the Samson Permian Basin Assets. Direct operating expenses include lease operating, gathering, processing, and production and other tax expenses. Lease operating expenses include the costs of maintaining and operating property and equipment on producing oil and natural gas leases and include field labor, insurance, maintenance, repairs, utilities and supplies, and well workover and


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SAMSON PERMIAN BASIN ASSETS
 
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
 
field expenses. Gathering and processing expenses include the costs of oil and/or natural gas taken in-kind for the use of gas processing facilities as well as maintenance, repair, and other operating costs incurred in gathering the production. Production and other taxes consist of severance and ad valorem taxes. Production taxes are recorded at the time transfer of title occurs. Such taxes represent a fixed percentage of production and are calculated and paid to the state governments in accordance with applicable regulations.
 
3.   Contingencies
 
The activities of the Samson Permian Basin Assets are subject to potential claims and litigation in the normal course of operations. Enduro’s management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the Samson Permian Basin Assets.
 
4.   Cash Flow Information (Unaudited)
 
Capital expenditures relating to the Samson Permian Basin Assets were approximately $799,000, $968,000, and $5,628,000 for the years ended December 31, 2010, 2009, and 2008, respectively. Other cash flow information is not available on a stand-alone basis for the Samson Permian Basin Assets.
 
5.   Subsequent Events
 
Subsequent events have been evaluated through May 9, 2011, the date the statements were available to be issued, to ensure that any subsequent events that met the criteria for recognition or disclosure in this report have been included. No subsequent events requiring recognition or disclosure have occurred.
 
6.   Supplemental Oil and Natural Gas Disclosures (Unaudited)
 
The following unaudited supplemental oil and natural gas disclosures were derived from reserve reports which were prepared by Enduro’s reserve engineers and are presented in accordance with the Financial Accounting Standards Board ASC Topic 932, Extractive Activities — Oil and Gas (“ASC 932”). The unaudited supplemental information reflects the revised oil and natural gas reserve estimation and disclosure requirements of the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC in 2008 and were effective December 31, 2009. The following unaudited supplemental information for 2010 and 2009 has been presented in accordance with the revised reserve estimation and disclosure rules, which were not applied retrospectively. Accordingly, the information for 2008 is presented in accordance with the oil and gas disclosure requirements effective during that period.
 
Oil and Natural Gas Reserve Quantities
 
Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing, and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The process of estimating quantities of oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for


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SAMSON PERMIAN BASIN ASSETS
 
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
 
each reserve. Consequently, material revisions to existing reserve estimates may occur from time to time.
 
The following table presents the estimated remaining net proved and proved developed oil and natural gas reserves of the Samson Permian Basin Assets and changes therein, for the periods indicated.
 
                         
    Oil
    Natural Gas
    Total
 
    (MBbls)     (MMcf)     (MBOE)  
 
January 1, 2008
    3,835       14,399       6,235  
Revisions of previous estimates
    (351 )     (517 )     (437 )
Production
    (246 )     (1,164 )     (440 )
                         
December 31, 2008
    3,238       12,718       5,358  
Revisions of previous estimates
    139       (150 )     114  
Production
    (233 )     (1,110 )     (418 )
                         
December 31, 2009
    3,144       11,458       5,054  
Revisions of previous estimates
    120       379       183  
Production
    (216 )     (1,056 )     (392 )
                         
December 31, 2010
    3,048       10,781       4,845  
                         
Proved developed reserves as of:
                       
December 31, 2008
    3,238       12,718       5,358  
December 31, 2009
    3,144       11,458       5,054  
December 31, 2010
    3,048       10,781       4,845  
 
Standardized Measure of Discounted Future Net Cash Flows
 
Estimated discounted future net cash flows and changes therein were determined for the Samson Permian Basin Assets in accordance with ASC 932. Future cash inflows for 2010 and 2009 were computed by applying the average prices of oil and natural gas during the 12-month period to the period-end quantities of those proved reserves (with consideration of price changes only to the extent provided by contractual arrangements). The average prices were determined using the arithmetic average of the prices in effect on the first day of the month for each month within the period. This same 12-month average price was also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. Future cash inflows for 2008 were computed by using the year-end oil and natural gas prices in accordance with the disclosure requirements effective during that period.
 
The prices per unit used for the Samson Permian Basin Assets’ proved reserves and future net revenues are as follows:
 
                         
    December 31,
    2010   2009   2008
 
Oil (per Bbl)
  $ 79.43     $ 61.18     $ 44.60  
Natural gas (per Mcf)
  $ 4.37     $ 3.83     $ 5.62  
 
Future development and production costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves based on period-end costs assuming continuation of existing economic conditions. No future income tax expense was


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SAMSON PERMIAN BASIN ASSETS
 
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
 
computed as taxable income arising from the operations of the properties accrues to the owner. An annual discount rate of 10% was used to reflect the timing of the future net cash flows.
 
Discounted future cash flow estimates like those shown below are not intended to present, nor should they be interpreted to present, the fair value of the Samson Permian Basin Assets’ oil and natural gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future commodity prices, interest rates, changes in development and production costs, and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.
 
The following table presents the estimates of the standardized measure of discounted future net cash flows from proved reserves of oil and natural gas for the periods indicated.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands)  
 
Future cash inflows
  $ 292,253     $ 239,673     $ 224,628  
Future production costs
    (107,372 )     (96,804 )     (92,314 )
                         
Future net cash flows
    184,881       142,869       132,314  
10% discount for estimating timing of cash flows
    (99,927 )     (73,986 )     (64,551 )
                         
Standardized measure of discounted future net cash flows
  $ 84,954     $ 68,883     $ 67,763  
                         
 
The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the periods indicated.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands)  
 
Sales of oil and natural gas produced, net of production costs
  $ (16,924 )   $ (12,389 )   $ (26,446 )
Net changes in prices and production costs
    25,022       10,094       (83,425 )
Revisions of previous quantity estimates
    3,361       1,650       (4,972 )
Accretion of discount
    6,888       6,776       16,207  
Timing and other
    (2,276 )     (5,011 )     4,330  
                         
Net change in standardized measure
    16,071       1,120       (94,306 )
Standardized measure, beginning of year
    68,883       67,763       162,069  
                         
Standardized measure, end of year
  $ 84,954     $ 68,883     $ 67,763  
                         


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CONOCOPHILLIPS PERMIAN BASIN ASSETS
 
UNAUDITED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
 
                 
    Three Months Ended March 31,  
    2011     2010  
    (In thousands)  
 
Revenues:
               
Oil
  $ 15,464     $ 12,632  
Natural gas
    1,572       1,526  
                 
Total revenues
    17,036       14,158  
                 
Direct operating expenses:
               
Lease operating
    4,162       4,169  
Gathering and processing
    47       56  
Production and other taxes
    1,385       1,185  
                 
Total direct operating expenses
    5,594       5,410  
                 
Excess of revenues over direct operating expenses
  $ 11,442     $ 8,748  
                 
 
The accompanying notes are an integral part of these statements.


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CONOCOPHILLIPS PERMIAN BASIN ASSETS
 
NOTES TO UNAUDITED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
 
1.   Basis of Presentation
 
On February 28, 2011 (the “Acquisition Date”), Enduro Resource Partners LLC (“Enduro”) completed the acquisition of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico (the “ConocoPhillips Permian Basin Assets”) from ConocoPhillips Company and a related subsidiary (collectively, “ConocoPhillips”) for a cash purchase price of approximately $314.2 million, subject to post-closing adjustments.
 
The accompanying unaudited statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of Enduro for periods subsequent to the Acquisition Date and of ConocoPhillips for periods prior to the Acquisition Date.
 
During the periods presented, the ConocoPhillips Permian Basin Assets were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying unaudited statements of revenues and direct operating expenses are not indicative of the financial condition or results of operations of the ConocoPhillips Permian Basin Assets and such amounts may not be representative of future operations.
 
These unaudited statements of revenues and direct operating expenses do not represent a complete set of financial statements reflecting the financial position, results of operations, shareholders’ equity, and cash flows of the ConocoPhillips Permian Basin Assets. In the opinion of management, the accompanying unaudited statements of revenues and direct operating expenses include all adjustments considered necessary for fair presentation on the basis described above. All adjustments are of a normal recurring nature.
 
2.   Contingencies
 
The activities of the ConocoPhillips Permian Basin Assets are subject to potential claims and litigation in the normal course of operations. Enduro’s management does not believe that any liability resulting from any pending or threatened litigation will have a material adverse effect on the operations or financial results of the ConocoPhillips Permian Basin Assets.
 
3.   Cash Flow Information
 
Capital expenditures relating to the ConocoPhillips Permian Basin Assets were approximately $6.0 million and $0.2 million for the three months ended March 31, 2011 and 2010, respectively. Other cash flow information is not available on a stand-alone basis for the ConocoPhillips Permian Basin Assets.
 
4.   Subsequent Events
 
Subsequent events have been evaluated through July 1, 2011, the date the statements were available to be issued, to ensure that any subsequent events that met the criteria for recognition or disclosure in this report have been included. No subsequent events requiring recognition or disclosure have occurred.


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Table of Contents

 
Report of Independent Registered Public Accounting Firm
 
To the Board of Managers and Members of Enduro Resource Partners LLC:
 
We have audited the accompanying statements of revenues and direct operating expenses of the ConocoPhillips Permian Basin Assets, described in Note 1, for the years ended December 31, 2010, 2009 and 2008. These statements are the responsibility of Enduro Resource Partners LLC’s management. Our responsibility is to express an opinion on these statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements are free of material misstatement. We were not engaged to perform an audit of the internal controls over financial reporting of the revenues and direct operating expenses of the ConocoPhillips Permian Basin Assets. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate for the circumstances, but not for the purpose of expressing an opinion on the effectiveness of internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statements. We believe that our audits provide a reasonable basis for our opinion.
 
The accompanying statements reflect the revenues and direct operating expenses of the ConocoPhillips Permian Basin Assets, as described in Note 1, and are not intended to be a complete presentation of the ConocoPhillips Permian Basin Assets’ revenues and expenses.
 
In our opinion, the statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the ConocoPhillips Permian Basin Assets for the years ended December 31, 2010, 2009 and 2008 in conformity with U.S. generally accepted accounting principles.
 
/s/ Ernst & Young LLP
 
Tulsa, Oklahoma
May 9, 2011


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CONOCOPHILLIPS PERMIAN BASIN ASSETS
 
 
                         
    Year Ended December 31,  
    2010     2009     2008  
          (In thousands)        
 
Revenues:
                       
Oil
  $ 52,062     $ 40,450     $ 80,014  
Natural gas
    7,025       5,801       11,746  
                         
Total revenues
    59,087       46,251       91,760  
                         
Direct operating expenses:
                       
Lease operating
    16,657       16,674       20,309  
Gathering and processing
    243       234       386  
Production and other taxes
    4,994       3,989       6,409  
                         
Total direct operating expenses
    21,894       20,897       27,104  
                         
Excess of revenues over direct operating expenses
  $ 37,193     $ 25,354     $ 64,656  
                         
 
The accompanying notes are an integral part of these statements.


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Table of Contents

CONOCOPHILLIPS PERMIAN BASIN ASSETS
 
 
1.   Basis of Presentation
 
On February 28, 2011, Enduro Resource Partners LLC (“Enduro”) completed the acquisition of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico (the “ConocoPhillips Permian Basin Assets”) from ConocoPhillips Company and a related subsidiary (collectively, “ConocoPhillips”) for a cash purchase price of approximately $314.2 million, subject to post-closing adjustments.
 
The accompanying statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of ConocoPhillips.
 
During the periods presented, the ConocoPhillips Permian Basin Assets were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying statements of revenues and direct operating expenses are not indicative of the financial condition or results of operations of the ConocoPhillips Permian Basin Assets and such amounts may not be representative of future operations.
 
Full separate financial statements prepared in accordance with generally accepted accounting principles are not presented as the information necessary to prepare such statements is neither readily available on an individual property basis nor practicable to obtain in these circumstances. Accordingly, the statements of revenues and direct operating expenses of the ConocoPhillips Permian Basin Assets are presented in lieu of the financial statements otherwise required under Rules 3-01 and 3-02 of Regulation S-X by the Securities and Exchange Commission (“SEC”).
 
2.   Significant Accounting Policies
 
(a)   Use of Estimates
 
Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the statements of revenues and direct operating expenses. Actual balances and results could be different from those estimates.
 
(b)   Revenue Recognition
 
Oil and natural gas revenues are recognized when such products have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibilities of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Revenues are reported net of royalties and other amounts due to third parties.
 
(c)   Direct Operating Expenses
 
Direct operating expenses are recognized when incurred and consist of the direct expenses of operating the ConocoPhillips Permian Basin Assets. Direct operating expenses include lease operating, gathering, processing, and production and other tax expenses. Lease operating expenses include the costs of maintaining and operating property and equipment on producing oil and natural gas leases and include field labor, insurance, maintenance, repairs, utilities and supplies, and well workover and field expenses. Gathering and processing expenses include the costs of oil and/or natural gas taken in-


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CONOCOPHILLIPS PERMIAN BASIN ASSETS
 
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
 
kind for the use of gas processing facilities as well as maintenance, repair, and other operating costs incurred in gathering the production. Production and other taxes consist of severance and ad valorem taxes. Production taxes are recorded at the time transfer of title occurs. Such taxes represent a fixed percentage of production and are calculated and paid to the state governments in accordance with applicable regulations.
 
3.   Contingencies
 
The activities of the ConocoPhillips Permian Basin Assets are subject to potential claims and litigation in the normal course of operations. Enduro’s management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the ConocoPhillips Permian Basin Assets.
 
4.   Cash Flow Information (Unaudited)
 
Capital expenditures relating to the ConocoPhillips Permian Basin Assets were approximately $28.5 million, $0.6 million, and $6.3 million for the years ended December 31, 2010, 2009, and 2008, respectively. Other cash flow information is not available on a stand-alone basis for the ConocoPhillips Permian Basin Assets.
 
5.   Subsequent Events
 
Subsequent events have been evaluated through May 9, 2011, the date the statements were available to be issued, to ensure that any subsequent events that met the criteria for recognition or disclosure in this report have been included. No subsequent events requiring recognition or disclosure have occurred.
 
6.   Supplemental Oil and Natural Gas Disclosures (Unaudited)
 
The following unaudited supplemental oil and natural gas disclosures were derived from reserve reports which were prepared by Enduro’s reserve engineers and are presented in accordance with the Financial Accounting Standards Board ASC Topic 932, Extractive Activities — Oil and Gas (“ASC 932”). The unaudited supplemental information reflects the revised oil and natural gas reserve estimation and disclosure requirements of the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC in 2008 and were effective December 31, 2009. The following unaudited supplemental information for 2010 and 2009 has been presented in accordance with the revised reserve estimation and disclosure rules, which were not applied retrospectively. Accordingly, the information for 2008 is presented in accordance with the oil and gas disclosure requirements effective during that period.
 
Oil and Natural Gas Reserve Quantities
 
Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing, and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The process of estimating quantities of oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reserve. Consequently, material revisions to existing reserve estimates may occur from time to time.


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Table of Contents

CONOCOPHILLIPS PERMIAN BASIN ASSETS
 
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
 
The following table presents the estimated remaining net proved and proved developed oil and natural gas reserves of the ConocoPhillips Permian Basin Assets and changes therein, for the periods indicated.
 
                         
    Oil
    Natural Gas
    Total
 
    (MBbls)     (MMcf)     (MBOE)  
 
January 1, 2008
    12,228       14,484       14,642  
Revisions of previous estimates
    (4,093 )     (2,263 )     (4,470 )
Production
    (805 )     (1,255 )     (1,014 )
                         
December 31, 2008
    7,330       10,966       9,158  
Revisions of previous estimates
    2,343       365       2,404  
Production
    (752 )     (1,276 )     (965 )
                         
December 31, 2009
    8,921       10,055       10,597  
Revisions of previous estimates
    1,477       1,784       1,774  
Production
    (705 )     (1,139 )     (895 )
                         
December 31, 2010
    9,693       10,700       11,476  
                         
Proved developed reserves as of:
                       
December 31, 2008
    7,330       10,966       9,158  
December 31, 2009
    8,921       10,055       10,597  
December 31, 2010
    9,314       9,407       10,882  
Proved undeveloped reserves as of:
                       
December 31, 2008
                 
December 31, 2009
                 
December 31, 2010
    379       1,293       594  
 
Standardized Measure of Discounted Future Net Cash Flows
 
Estimated discounted future net cash flows and changes therein were determined for the ConocoPhillips Permian Basin Assets in accordance with ASC 932. Future cash inflows for 2010 and 2009 were computed by applying the average prices of oil and natural gas during the 12-month period to the period-end quantities of those proved reserves (with consideration of price changes only to the extent provided by contractual arrangements). The average prices were determined using the arithmetic average of the prices in effect on the first day of the month for each month within the period. This same 12-month average price was also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. Future cash inflows for 2008 were computed by using the year-end oil and natural gas prices in accordance with the disclosure requirements effective during that period.
 
The prices per unit used for the ConocoPhillips Permian Basin Assets’ proved reserves and future net revenues are as follows:
 
                         
    December 31,
    2010   2009   2008
 
Oil (per Bbl)
  $ 79.43     $ 61.18     $ 44.60  
Natural gas (per Mcf)
  $ 4.37     $ 3.83     $ 5.62  
 
Future development and production costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves based on period-end


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Table of Contents

CONOCOPHILLIPS PERMIAN BASIN ASSETS
 
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
 
costs assuming continuation of existing economic conditions. No future income tax expense was computed as taxable income arising from the operations of the properties accrues to the owner. An annual discount rate of 10% was used to reflect the timing of the future net cash flows.
 
Discounted future cash flow estimates like those shown below are not intended to present, nor should they be interpreted to present, the fair value of the ConocoPhillips Permian Basin Assets’ oil and natural gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future commodity prices, interest rates, changes in development and production costs, and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.
 
The following table presents the estimates of the standardized measure of discounted future net cash flows from proved reserves of oil and natural gas for the periods indicated.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
          (In thousands)        
 
Future cash inflows
  $ 788,822     $ 562,323     $ 378,542  
Future production costs
    (407,974 )     (331,913 )     (228,540 )
Future development costs
    (6,000 )            
Future net cash flows
    374,848       230,410       150,002  
                         
10% discount for estimating timing of cash flows
    (179,827 )     (103,004 )     (61,428 )
                         
Standardized measure of discounted future net cash flows
  $ 195,021     $ 127,406     $ 88,574  
                         
 
The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the periods indicated.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
          (In thousands)        
 
Extensions and discoveries, net of future
development costs
  $ 11,065     $     $  
Sales of oil and natural gas produced, net of production costs
    (37,193 )     (25,354 )     (64,656 )
Net changes in prices and production costs
    69,967       31,046       (206,394 )
Revisions of previous quantity estimates
    21,549       30,869       (36,796 )
Accretion of discount
    12,741       8,857       36,168  
Change in estimated future development costs
    (5,721 )            
Timing and other
    (4,793 )     (6,586 )     (1,427 )
                         
Net change in standardized measure
    67,615       38,832       (273,105 )
Standardized measure, beginning of year
    127,406       88,574       361,679  
                         
Standardized measure, end of year
  $ 195,021     $ 127,406     $ 88,574  
                         


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Table of Contents

 
UNAUDITED PRO FORMA COMBINED STATEMENTS OF REVENUES
AND DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES
 
Introduction
 
The following unaudited pro forma combined statements of revenues and direct operating expenses represent the historical revenues and direct operating expenses of the Predecessor Underlying Properties, as adjusted to give effect to the acquisition of certain properties by Enduro Sponsor located in the Permian Basin in Texas and New Mexico from Samson Investment Company (the “Samson Permian Basin Assets”) and the acquisition of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico from ConocoPhillips Company (the “ConocoPhillips Permian Basin Assets”) as if such acquisitions had occurred on January 1, 2009.
 
These unaudited pro forma combined statements of revenues and direct operating expenses are for informational purposes only. They do not purport to present the results of the combined historical revenues and direct operating expenses of the Underlying Properties that would have actually occurred had the acquisitions of the Samson Permian Basin Assets and the ConocoPhillips Permian Basin Assets occurred on January 1, 2009.
 
The unaudited pro forma combined statements of historical revenues and direct operating expenses should be read in conjunction with “Discussion and Analysis of Pro Forma Combined Historical Results of the Underlying Properties,” the audited statements of revenues and direct operating expenses of the Predecessor Underlying Properties, the audited statements of revenues and direct operating expenses of the Samson Permian Basin Assets, and the audited statements of revenues and direct operating expenses of the ConocoPhillips Permian Basin Assets included in this prospectus and elsewhere in the registration statement.


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Table of Contents

 
UNAUDITED PRO FORMA COMBINED STATEMENT OF REVENUES AND
DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES

THREE MONTHS ENDED MARCH 31, 2011
 
                                 
    Predecessor
    Samson
    ConocoPhillips
    Total
 
    Underlying
    Permian Basin
    Permian Basin
    Underlying
 
    Properties     Assets     Assets     Properties  
    (In thousands)  
 
Revenues:
                               
Oil
  $ 335     $ 4,351     $ 15,464     $ 20,150  
Natural gas
    4,477       1,213       1,572       7,262  
                                 
Total revenues
    4,812       5,564       17,036       27,412  
                                 
Direct operating expenses:
                               
Lease operating
    1,238       785       4,162       6,185  
Gathering and processing
    386       56       47       489  
Production and other taxes
    243       377       1,385       2,005  
                                 
Total direct operating expenses
    1,867       1,218       5,594       8,679  
                                 
                                 
Excess of revenues over direct operating expenses
  $ 2,945     $ 4,346     $ 11,442     $ 18,733  
                                 


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UNAUDITED PRO FORMA COMBINED STATEMENT OF REVENUES
AND DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES

YEAR ENDED DECEMBER 31, 2010
 
                                         
    Predecessor
    Samson
    ConocoPhillips
    Total
       
    Underlying
    Permian Basin
    Permian Basin
    Underlying
       
    Properties     Assets     Assets     Properties        
    (In thousands)        
 
Revenues:
                                       
Oil
  $ 1,345     $ 16,626     $ 52,062     $ 70,033          
Natural gas
    21,112       5,650       7,025       33,787          
                                         
Total revenues
    22,457       22,276       59,087       103,820          
                                         
Direct operating expenses:
                                       
Lease operating
    4,484       3,438       16,657       24,579          
Gathering and processing
    1,522       212       243       1,977          
Production and other taxes
    1,373       1,702       4,994       8,069          
                                         
Total direct operating expenses
    7,379       5,352       21,894       34,625          
                                         
Excess of revenues over direct operating expenses
  $ 15,078     $ 16,924     $ 37,193     $ 69,195          
                                         


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UNAUDITED PRO FORMA COMBINED STATEMENT OF REVENUES
AND DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES

YEAR ENDED DECEMBER 31, 2009
 
                                         
    Predecessor
    Samson
    ConocoPhillips
    Total
       
    Underlying
    Permian Basin
    Permian Basin
    Underlying
       
    Properties     Assets     Assets     Properties        
    (In thousands)        
 
Revenues:
                                       
Oil
  $ 1,685     $ 13,174     $ 40,450     $ 55,309          
Natural gas
    22,519       4,733       5,801       33,053          
                                         
Total revenues
    24,204       17,907       46,251       88,362          
                                         
Direct operating expenses:
                                       
Lease operating
    5,365       3,783       16,674       25,822          
Gathering and processing
    1,474       177       234       1,885          
Production and other taxes
    1,965       1,558       3,989       7,512          
                                         
Total direct operating expenses
    8,804       5,518       20,897       35,219          
                                         
Excess of revenues over direct operating expenses
  $ 15,400     $ 12,389     $ 25,354     $ 53,143          
                                         


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Report of Independent Registered Public Accounting Firm
 
To the Unitholder of Enduro Royalty Trust:
 
We have audited the accompanying statement of assets and trust corpus of Enduro Royalty Trust (the “Trust”) as of May 12, 2011. This financial statement is the responsibility of the management of Enduro Resource Partners LLC. Our responsibility is to express an opinion on this financial statement based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement of assets and trust corpus is free of material misstatement. We were not engaged to perform an audit of the internal controls over financial reporting of the Trust. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate for the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Trust’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement of assets and trust corpus, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement. We believe that our audit provides a reasonable basis for our opinion.
 
As described in Note 2, this statement has been prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles.
 
In our opinion, the statement of assets and trust corpus referred to above presents fairly, in all material respects, the financial position of the Trust as of May 12, 2011, on the basis of accounting described in Note 2.
 
/s/  Ernst & Young LLP
 
Fort Worth, Texas
May 12, 2011


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ENDURO ROYALTY TRUST
 
STATEMENT OF ASSETS AND TRUST CORPUS
 
         
    May 12, 2011  
 
ASSETS
Cash
  $ 10  
         
 
TRUST CORPUS
Trust Corpus
  $ 10  
         
 
The accompanying notes are an integral part of this financial statement.


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ENDURO ROYALTY TRUST
 
NOTES TO STATEMENT OF ASSETS AND TRUST CORPUS
 
1.   Organization of the Trust
 
Enduro Royalty Trust (the “Trust”) is a Delaware statutory trust formed on May 3, 2011 under the Delaware Statutory Trust Act pursuant to a Trust Agreement (the “Trust Agreement”) among Enduro Resource Partners LLC (“Enduro”), as trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and Wilmington Trust Company, as Delaware Trustee (the “Delaware Trustee”).
 
The Trust was created to acquire and hold a net profits interest (the “Net Profits Interest”) for the benefit of the Trust unitholders pursuant to an agreement between Enduro, the Trustee, and the Delaware Trustee. In connection with the closing of the initial public offering of trust units, Enduro intends to convey, or cause to be conveyed, the Net Profits Interest to the Trust in exchange for trust units. The Net Profits Interest represents an interest in underlying properties consisting of Enduro’s interests in specified oil and natural gas properties located in Texas, Louisiana and New Mexico (the “Underlying Properties”).
 
The Net Profits Interest is passive in nature and neither the Trust nor the Trustee has any control over, or responsibility for, costs relating to the operation of the Underlying Properties. The Net Profits Interest entitles the Trust to receive 80% of the net profits from the sale of oil and natural gas production of the Underlying Properties.
 
The Trustee can authorize the Trust to borrow money to pay trust administrative or incidental expenses that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from the Trustee as a lender provided the terms of the loan are fair to the trust unitholder and similar to the terms it would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. The Trustee may also deposit funds awaiting distribution in an account with itself, if the interest paid to the Trust at least equals amounts paid by the Trustee on similar deposits, and make other short-term investments with the funds distributed to the Trust.
 
2.   Trust Significant Accounting Policies
 
(a)   Basis of Accounting
 
The Trust uses the modified cash basis of accounting to report Trust receipts of the Net Profits Interest and payments of expenses incurred. The Net Profits Interest represents the right to receive revenues (oil and natural gas sales), less direct operating expenses (lease operating expenses and production and property taxes) and development expenses of the Underlying Properties plus any payments made or net of payments received in connection with the settlement of certain hedge contracts, multiplied by 80%. Cash distributions of the Trust will be made based on the amount of cash received by the Trust pursuant to terms of the conveyance creating the Net Profits Interest.
 
The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust’s assets, liabilities, Trust corpus, earnings and distributions as follows:
 
(i) Income from Net Profits Interest is recorded when distributions are received by the Trust;
 
(ii) Distributions to Trust unitholders are recorded when paid by the Trust;
 
(iii) Trust general and administrative expenses (which includes the Trustee’s fees as well as accounting, engineering, legal, and other professional fees) are recorded when paid; and


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ENDURO ROYALTY TRUST
 
NOTES TO STATEMENT OF ASSETS AND TRUST CORPUS — (Continued)
 
(iv) Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under accounting principles generally accepted in the United States of America (“GAAP”).
 
Amortization of the investment in Net Profits Interest is calculated on a unit-of-production basis and is charged directly to Trust corpus. Such amortization does not affect cash earnings of the Trust.
 
Investment in the Net Profits Interest is periodically assessed to determine whether its aggregate value has been impaired below its total capitalized cost based on the Underlying Properties. If an impairment loss is indicated by the carrying amount of the assets exceeding the sum of the undiscounted expected future net cash flows, then an impairment loss is recognized for the amount by which the carrying amount of the asset exceeds its estimated fair value.
 
While these statements differ from financial statements prepared in accordance with GAAP, the modified cash basis of reporting revenues, expenses, and distributions is considered to be the most meaningful because monthly distributions to the Trust unitholders are based on net cash receipts. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.
 
To date, the Net Profits Interest has not been conveyed by Enduro to the Trust. Thus, there have been no receipts from the Net Profits Interest and no administrative expenses been incurred.
 
(b)   Use of Estimates
 
The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
 
3.   Income Taxes
 
Tax counsel to the Trust advised the Trust at the time of formation that for U.S. federal income tax purposes, the Trust will be treated as a grantor trust and will not be subject to tax at the trust level. Trust unitholders will be treated for such purposes as owning a direct interest in the assets of the Trust, and each trust unitholder will be taxed directly on his pro rata share of the income and gain attributable to the assets of the Trust and will be entitled to claim his pro rata share of the deductions and expenses attributable to the assets of the Trust.
 
4.   Distributions to Unitholders
 
Each month, the Trustee determines the amount of funds available for distribution to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the Net Profits Interest and other sources (such as interest earned on any amounts reserved by the Trustee) that month, over the Trust’s liabilities for that month, subject to adjustments for changes made by the Trustee during the month in any cash reserves established for future liabilities of the Trust. Distributions are made to the holders of trust units as of the applicable record date (generally the 15th day of each calendar month) and are payable on or before the 10th business day after the record date. To date, there have been no distributions.


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ENDURO ROYALTY TRUST
 
UNAUDITED PRO FORMA FINANCIAL STATEMENTS
 
Introduction
 
The following unaudited pro forma statement of assets and trust corpus and unaudited pro forma statements of distributable income for the Trust have been prepared to illustrate the conveyance of the Net Profits Interest in the Underlying Properties by Enduro Sponsor to the Trust. The unaudited pro forma statement of assets and trust corpus presents the beginning statement of assets and trust corpus of the Trust as of May 12, 2011, as adjusted to give effect to the Net Profits Interest conveyance as if it had occurred on May 12, 2011. The unaudited pro forma statements of distributable income for the three months ended March 31, 2011 and for the year ended December 31, 2010 give effect to the Net Profits Interest conveyance as if it occurred on January 1, 2010, reflecting only pro forma adjustments expected to have a continuing impact on the combined results.
 
These unaudited pro forma financial statements are for informational purposes only. They do not purport to present the results that would have actually occurred had the Net Profits Interest conveyance been completed on the assumed dates or for the periods presented, or which may be realized in the future.
 
To produce the pro forma financial statements, management of Enduro Sponsor made certain estimates. The accompanying unaudited pro forma statement of assets and trust corpus assumes a May 12, 2011 issuance of 33,000,000 trust units at an assumed public offering price of $           per unit. The accompanying unaudited pro forma statements of distributable income for the three months ended March 31, 2011 and for the year ended December 31, 2010 have been prepared assuming trust formation and Net Profits Interest conveyance at the beginning of the period presented.
 
These estimates are based on the most recently available information. To the extent there are significant changes in these amounts, the assumptions and estimates herein could change significantly. The unaudited pro forma statement of assets and trust corpus and unaudited pro forma statements of distributable income should be read in conjunction with the accompanying notes to such unaudited pro forma financial statements and the audited statement of assets and trust corpus of the Trust, including the related notes, included in this prospectus and elsewhere in the registration statement.


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ENDURO ROYALTY TRUST
 
UNAUDITED PRO FORMA STATEMENT OF ASSETS AND TRUST CORPUS
 
                         
    May 12, 2011  
    Historical     Adjustments     Pro Forma  
    (In thousands)  
 
ASSETS
Cash
  $     $     $  
Investment in Net Profits Interest (See Note 5)
          825,000       825,000  
                         
    $     $ 825,000     $ 825,000  
                         
TRUST CORPUS
Trust Units Issued and Outstanding
  $     $ 825,000     $ 825,000  
                         
 
The accompanying notes are an integral part of these unaudited pro forma financial statements.


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ENDURO ROYALTY TRUST
 
UNAUDITED PRO FORMA STATEMENTS OF DISTRIBUTABLE INCOME
 
                 
    Three Months
       
    Ended
    Year Ended
 
    March 31, 2011     December 31, 2010  
    (In thousands)  
 
Historical Results
               
Income from the Net Profits Interest (See Note 4)
  $ 5,302     $ 25,727  
Pro Forma Adjustments
               
Less: Trust general and administrative expenses (See Note 5)
    213       850  
                 
Distributable income
  $ 5,089     $ 24,877  
                 
Distributable income per unit
  $ 0.15     $ 0.75  
                 
 
The accompanying notes are an integral part of these unaudited pro forma financial statements.


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ENDURO ROYALTY TRUST
 
 
1.   Basis of Presentation
 
In connection with the closing of the initial public offering of trust units, Enduro Sponsor will convey, or cause to be conveyed, to Enduro Royalty Trust (the “Trust”) a net profits interest (the “Net Profits Interest”) in certain oil and natural gas producing properties located in Texas, Louisiana, and New Mexico (the “Underlying Properties”). The Net Profits Interest entitles the Trust to receive 80% of the net profits attributable to Enduro Sponsors’ interest from the sale of oil and natural gas production from the Underlying Properties.
 
The unaudited pro forma statement of assets and trust corpus presents the beginning statement of assets and trust corpus of the Trust as of May 12, 2011, as adjusted to give effect to the Net Profits Interest conveyance as if it had occurred on May 12, 2011. The unaudited pro forma statements of distributable income for the three months ended March 31, 2011 and for the year ended December 31, 2010 give effect to the Net Profits Interest conveyance as if it occurred on January 1, 2010, reflecting only pro forma adjustments expected to have a continuing impact on the combined results.
 
The Trust was formed on May 3, 2011 under Delaware law to acquire and hold the Net Profits Interest for the benefit of the Trust unitholders. The initial contribution to the Trust was $10. The Net Profits Interest is passive in nature and neither the Trust nor The Bank of New York Mellon Trust Company, N.A., as trustee (the “Trustee”) will have any control over, or responsibility for, costs relating to the operation of the Underlying Properties.
 
The unaudited pro forma financial statements should be read in conjunction with the Statement of Assets and Trust Corpus for the Trust and the Unaudited Pro Forma Combined Statements of Revenues and Direct Operating Expenses.
 
2.   Trust Accounting Policies
 
These Unaudited Pro Forma Financial Statements were prepared using the accrual basis information from the historical revenues and direct operating expenses for each of the Predecessor Underlying Properties, the Samson Permian Basin Assets, and the ConocoPhillips Permian Basin Assets. The Trust uses the modified cash basis of accounting to report Trust receipts of the Net Profits Interest and payments of expenses incurred. Actual cash receipts may vary due to timing delays of actual cash receipts from the property operators or purchasers. The actual cash distributions of the Trust will be made based on the terms of the conveyance creating the Trust’s Net Profits Interest which is on a modified cash basis of accounting.
 
Investment in the Net Profits Interest is recorded initially at its fair value and periodically assessed to determine whether its aggregate value has been impaired below its total capitalized cost on the Underlying Properties. The Trust will provide a write-down to its investment in the Net Profits Interest to the extent that total capitalized costs, less accumulated depletion, depreciation, and amortization, exceed undiscounted future net revenues attributable to the Trust’s interests in the proved oil and natural gas reserves of the Underlying Properties.
 
Enduro Sponsor believes that the assumptions used provide a reasonable basis for presenting the significant effects directly attributable to this transaction.
 
These unaudited pro forma financial statements should be read in conjunction with the Unaudited Pro Forma Combined Statements of Revenues and Direct Operating Expenses and related notes for the periods presented.


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ENDURO ROYALTY TRUST
 
NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS — (Continued)
 
3.   Income Taxes
 
The Trust is a Delaware statutory trust and is not required to pay federal or state income taxes. Accordingly, no provision for Federal or state income taxes has been made.
 
4.   Income from Net Profits Interest
 
The table below outlines the calculation of Trust income from the Net Profits Interest derived from the excess of revenues over direct operating expenses of the Underlying Properties for the three months ended March 31, 2011 and for the year ended December 31, 2010.
 
                 
    Three Months Ended
    Year Ended
 
    March 31, 2011     December 31, 2010  
 
Pro forma excess of revenues over direct operating expenses of the Underlying Properties
  $ 18,733     $ 69,195  
Development costs(a)
    (12,105 )     (37,036 )
                 
Excess of revenues over direct operating expenses and development costs
    6,628       32,159  
Multiplied by Net Profits Interest
    80%       80%  
                 
Trust Income from Net Profits Interest
  $ 5,302     $ 25,727  
                 
 
 
(a) Per the terms of the net profits interest, development costs are to be deducted when calculating the distributable income to the Trust.
 
5.   Pro Forma Adjustments
 
The Net Profits Interest is recorded at its fair value and is calculated as follows as of May 12, 2011:
 
         
Gross cash proceeds from the sale of trust units
  $ 330,000  
Trust units held by Enduro Sponsor
    495,000  
         
Fair value of investment in Net Profits Interest
  $ 825,000  
         
 
Estimated annual trust administrative expenses are $850,000 ($212,500 quarterly). Administrative expenses for subsequent years could be greater or less depending on future events that cannot be predicted. The Trust’s general and administrative expenses include annual fees to Trustees, legal fees, accounting fees, engineering fees, printing costs, and other expenses properly chargeable to the Trust.


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The trust units are not interests in or obligations of
Enduro Sponsor


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Business and Properties of Enduro Sponsor
 
Enduro Sponsor is a privately-held Delaware limited liability company engaged in the production and development of oil and natural gas from properties located in Texas, Louisiana and New Mexico. Enduro Sponsor was formed on March 3, 2010.
 
The Underlying Properties were acquired in three separate transactions and are located in two different geographic regions: the Permian Basin and East Texas/North Louisiana. Enduro Sponsor’s oil and natural gas properties in the East Texas/North Louisiana region were acquired from Denbury Resources Inc. in December 2010, and Enduro Sponsor’s oil and natural gas properties in the Permian Basin of Texas and New Mexico were acquired from Samson Investment Company and ConocoPhillips Company in January 2011 and February 2011, respectively. After giving pro forma effect to the conveyance of the Net Profits Interest to the trust, the offering of the trust units contemplated by this prospectus and the application of the net proceeds as described in “Use of Proceeds,” as of March 31, 2011, Enduro Sponsor would have had total assets of $662.8 million and total liabilities of $107.7 million. For an explanation of the pro forma adjustments, please read “Financial Statements of Enduro Sponsor — Unaudited Pro Forma Financial Statements — Introduction.”
 
As of December 31, 2010, Enduro Sponsor held interests in approximately 4,866 gross (919 net) producing wells, and its proved reserves were approximately 32.8 MMBoe. As of December 31, 2010, all of the total proved reserves attributable to the Underlying Properties, based on PV-10 value, were operated by Third Party Operators, other than the Stockman Field in East Texas which is primarily operated by Enduro Sponsor. Petrohawk, EXCO Resources and Enduro Sponsor operate the acreage in the East Texas/North Louisiana region. Apache and Occidental are the two largest operators of Enduro Sponsor’s acreage in the Permian Basin region. These Third Party Operators have many years of experience in maximizing production response from mature oil and natural gas fields.
 
The trust units do not represent interests in, or obligations of, Enduro Sponsor.
 
Management of Enduro Sponsor
 
Set forth in the table below are the names, ages and titles of the managers and executive officers of Enduro Sponsor.
 
             
Name
 
Age
 
Title
 
Jon S. Brumley
    40     President and Chief Executive Officer
John W. Arms
    44     Executive Vice President and Chief Operating Officer
Kimberly A. Weimer
    32     Vice President and Chief Financial Officer
Bill R. Pardue
    38     Director, Engineering and Operations
David J. Grahek
    57     Director, Geology
David Leuschen
    60     Manager
Pierre F. Lapeyre, Jr. 
    48     Manager
N. John Lancaster
    43     Manager
I. Jon Brumley
    72     Manager
 
Jon S. Brumley co-founded Enduro Sponsor and has been the President and Chief Executive Officer of Enduro Sponsor and a member of the Enduro Sponsor Board since March 2010. Mr. Brumley is responsible for the coordination and supervision of exploration and production and the acquisition of Enduro Sponsor’s oil and natural gas reserves. Mr. Brumley was the Chief Executive Officer of EAC from January 2006 until March 2010 when it was sold to Denbury Resources Inc., a publicly traded exploration and production company. At EAC, Mr. Brumley also served as President from August 2002 until March 2010, a director on the Board of Directors from April 1999 until May 2001 and from November 2001 until March 2010 and Executive Vice President of Business Development and Corporate Secretary from April 1998 until August 2002. Mr. Brumley also served as President and Chief Executive Officer of Encore GP LLC, the managing member of Encore Energy, a publicly traded master


ENDURO-2


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limited partnership whose general partner was owned by EAC from February 2007 until March 2010. Prior to joining EAC, Mr. Brumley held management positions at MESA Petroleum and Pioneer Natural Resources Company. Mr. Brumley received a Bachelor of Business Administrations in Marketing from the University of Texas.
 
John W. Arms co-founded Enduro Sponsor and has been the Executive Vice President and Chief Operating Officer and a member of the Enduro Sponsor Board since March 2010. Mr. Arms is responsible for the coordination and supervision of acquisitions and the engineering, enhancement and exploitation of Enduro Sponsor’s existing properties as well as the engineering analysis and evaluation of its future reserve acquisitions. Prior to joining Enduro Sponsor, Mr. Arms served as Senior Vice President of Acquisitions at EAC and Encore Energy from February 2007 until its acquisition by Denbury Resources Inc. in March 2010. At EAC, Mr. Arms also served as Vice President of Business Development from September 2001 until February 2007 and as Manager of Acquisitions and in various other petroleum engineering positions from November 1998 until September 2001. Prior to joining EAC, Mr. Arms held various positions of responsibility at XTO Energy and ARCO Oil and Gas Company. Mr. Arms received his Bachelor of Science in Petroleum Engineering from the Colorado School of Mines.
 
Kimberly A. Weimer has been the Vice President and Chief Financial Officer of Enduro Sponsor since April 2010. Prior to joining Enduro Sponsor, Ms. Weimer served as the Director of Investor Relations of EAC from October 2008 until its acquisition by Denbury Resources Inc. in March 2010. From May 2007 until October 2008, she was the Senior Manager of Financial Reporting at EAC responsible for all aspects of SEC reporting for Encore Energy Partners LP. During this timeframe, Encore Energy Partners completed its initial public offering and was listed on the New York Stock Exchange, completed two follow-on equity offerings and purchased over $500 million in assets. Prior to joining EAC in 2007, Ms. Weimer worked in public accounting, beginning her career at Arthur Andersen. From May 2005 to May 2007, Ms. Weimer served as an Audit Manager at Cherry, Bekaert & Holland. Ms. Weimer received a Bachelor of Science in Accounting and Finance from Louisiana State University. She is a Certified Public Accountant.
 
Bill R. Pardue has been the Director, Engineering and Operations of Enduro Sponsor since May 2010. Prior to joining Enduro Sponsor, Mr. Pardue served as the Asset Manager of Encore Energy from May 2007 to May 2010. Mr. Pardue also served as the Engineering Manager for EAC from June 2005 until May 2007 in the Permian and Mid-Continent regions. At EAC, Mr. Pardue also worked in various petroleum engineering positions from November 2000 until May 2005. Prior to joining EAC, Mr. Pardue worked as a production and reservoir engineer for Meridian Oil/Burlington Resources from 1996 until 2000. Mr. Pardue received a Bachelor of Science in Petroleum Engineering from Texas Tech University and a Master of Business Administration from Texas Christian University. Mr. Pardue is also a registered professional engineer in the state of Texas.
 
David J. Grahek has been the Director, Geology of Enduro Sponsor since June 2010. Prior to joining Enduro Sponsor, Mr. Grahek served as Geologic Advisor of EAC from June 2005 until its acquisition by Denbury Resources, Inc., in March 2010. Prior to joining EAC, Mr. Grahek held various positions of responsibility with G&G Exploration Inc. and Union Pacific Resources Company. Mr. Grahek has over 35 years of petroleum geology experience. Mr. Grahek received his Bachelor of Science in Geology from the University of Southern Colorado and completed post graduate work at the Colorado School of Mines.
 
David Leuschen has been a member of the Enduro Sponsor Board since March 2010. Mr. Leuschen is a founder and Senior Managing Director of Riverstone. Prior to co-founding Riverstone, Mr. Leuschen was a Partner and Managing Director at Goldman, Sachs & Co. and founder and head of the Goldman, Sachs & Co. Global Energy & Power Group. Mr. Leuschen joined Goldman, Sachs & Co. in 1977 and became head of the Global Energy & Power Group in 1985 and a Partner in 1986. He remained with Goldman, Sachs & Co. until leaving to found Riverstone. Mr. Leuschen has served as a director of Cambridge Energy Research Associates, Cross Timbers Oil Company (predecessor to XTO


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Energy), J. Aron Resources, Mega Energy, Inc. and Natural Meats Montana. He currently serves on the boards of directors of Legend Natural Gas, Dynamic Industries, Dynamic Offshore Resources, Titan Operating, Northern Blizzard and Barra Energia. He is also president of Switchback Ranch LLC and has served on a number of non-profit boards of directors. Mr. Leuschen received his Bachelor of Arts from Dartmouth and his Master of Business Administration from Dartmouth’s Amos Tuck School of Business.
 
Pierre F. Lapeyre, Jr. has been a member of the Enduro Sponsor Board since March 2010. Mr. Lapeyre is a founder and Senior Managing Director of Riverstone. Prior to co-founding Riverstone, Mr. Lapeyre was a Managing Director at Goldman, Sachs & Co. in its Global Energy & Power Group. Mr. Lapeyre joined Goldman, Sachs & Co. in 1986 and spent his 14-year investment banking career focused on energy and power, particularly the midstream/pipeline and oil service sectors. Mr. Lapeyre’s responsibilities included client coverage and leading the execution of a wide variety of mergers and acquisitions, initial public offerings, strategic advisory and capital markets financings for clients across all sectors of the industry. Mr. Lapeyre serves on the boards of directors of Legend Natural Gas, Titan Specialties, Dynamic Industries, Titan Operating, Three Rivers, Northern Blizzard, Dynamic Offshore Resources and Quorum Technologies. Mr. Lapeyre received his Bachelor of Science in Finance and Economics from the University of Kentucky and his Master of Business Administration from the University of North Carolina at Chapel Hill.
 
N. John Lancaster has been a member of the Enduro Sponsor Board since March 2010. Mr. Lancaster is a Partner and Managing Director of Riverstone. Mr. Lancaster joined Riverstone in 2000 and is responsible for the sourcing and management of investments across the energy industry, with a particular emphasis on the oilfield service and exploration and production sectors. Prior to joining Riverstone, Mr. Lancaster was a Director with The Beacon Group, LLC, a privately held firm specializing in principal investing and strategic advisory services in the energy and other industries. Mr. Lancaster began his career at Bankers Trust and later at CS First Boston, spending time as an investment banker and equity research analyst focused on the oil service and unregulated gas transmission sectors of the energy industry. Mr. Lancaster serves on the boards of directors of Cobalt International, Titan Specialties, Dynamic Industries, Dynamic Offshore Resources, Cuadrilla Resources, Hudson Products, Liberty Resources, and Barra Energia. Mr. Lancaster received his Bachelor of Business Administration from the University of Texas, where he serves on the McCombs School of Business Advisory Council, and his Master of Business Administration from Harvard Business School.
 
I. Jon Brumley has been a member of the Enduro Sponsor Board since March 2010. Mr. Brumley served as the Chairman of the Board of Directors of Encore GP LLC from February 2007 to March 2010. Mr. Brumley also served as the Chairman of the Board of Directors of EAC since its inception in April 1998 until March 2010, the Chief Executive Officer from its inception until December 2005 and President from its inception until August 2002. Beginning in August 1996, Mr. Brumley served as Chairman and Chief Executive Officer of MESA Petroleum until MESA’s merger in August 1997 with Parker & Parsley to form Pioneer Natural Resources Company. He served as Chairman and Chief Executive Officer of Pioneer until joining EAC in 1998. Mr. Brumley received a Bachelor of Business Administration from the University of Texas and a Master of Business Administration from the University of Pennsylvania Wharton School of Business.
 
Compensation Discussion and Analysis
 
The trust was formed in May 2011 and does not have any executive officers, directors or employees. The trust has not paid or accrued any obligations with respect to management compensation or benefits for directors and executive officers. This Compensation Discussion and Analysis provides an overview and analysis of the elements of the compensation program for 2010 for the following individuals who were executive officers of Enduro Sponsor and who are referred to


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collectively as the named executive officers of Enduro Sponsor in this Compensation Discussion and Analysis:
 
  •      Jon S. Brumley, President and Chief Executive Officer of Enduro Sponsor,
 
  •      John W. Arms, Executive Vice President and Chief Operating Officer of Enduro Sponsor,
 
  •      Kimberly A. Weimer, Vice President and Chief Financial Officer of Enduro Sponsor,
 
  •      Bill R. Pardue, Director, Engineering and Operations of Enduro Sponsor, and
 
  •      David J. Grahek, Director, Geology of Enduro Sponsor.
 
The above named executive officers of Enduro Sponsor have not and will not receive any direct compensation from the trust.
 
Overview
 
Enduro Sponsor’s compensation program for the named executive officers for 2010 was determined by the Enduro Sponsor Board in connection with Enduro Sponsor’s formation in early 2010 with the following primary objectives:
 
  •      attract and retain the highest quality executive officers in Enduro Sponsor’s industry;
 
  •      provide incentives that will reward the named executive officers as a group for Enduro Sponsor’s performance; and
 
  •      provide incentives that will reward the named executive officers for their individual performance and contributions to Enduro Sponsor’s success.
 
The Enduro Sponsor Board felt that these objectives were best met by providing a mix of cash and equity-based compensation to the named executive officers, as described below.
 
Setting Executive Compensation
 
The Enduro Sponsor Board determines all elements of compensation for the named executive officers, including base salaries and the size, timing and allocation of any cash or equity-based incentive awards payable to the named executive officers. The Enduro Sponsor Board makes these determinations based upon recommendations from Enduro Sponsor’s chief executive officer (with respect to named executive officers other than the chief executive officer) and the Enduro Sponsor Board’s subjective evaluation, based upon the judgment and industry experience of its members, of each named executive officer’s position, responsibilities and individual performance.
 
Elements of Compensation
 
For 2010, compensation for the named executive officers consisted of base salary, discretionary cash bonuses and long-term equity-based compensation awards.
 
Base Salary.  Base salaries are paid to the named executive officers to recognize the scope and performance of duties and to encourage retention by providing a guaranteed income stream. The Enduro Sponsor Board established base salaries for the named executive officers based on various factors, including the recommendation of Enduro Sponsor’s chief executive officer (with respect to named executive officers other than the chief executive officer) and the Enduro Sponsor Board’s determination, based upon the judgment and industry experience of its members, of amounts it considered necessary to (i) attract and retain high quality executives, (ii) reflect the responsibilities of the named executive officers and (iii) recognize demonstrated proficiency and performance of the named executive officers.


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Based upon the foregoing considerations, the Enduro Sponsor Board determined to establish 2010 base salaries for the named executive officers in the following amounts:
 
         
Name and Principal Position
  2010 Base Salary  
 
Jon S. Brumley
President and Chief Executive Officer
  $ 325,000  
John W. Arms
Executive Vice President and Chief Operating Officer
  $ 325,000  
Kimberly A. Weimer
Vice President and Chief Financial Officer
  $ 165,000  
Bill R. Pardue
Director, Engineering and Operations
  $ 165,000  
David J. Grahek
Director, Geology
  $ 165,000  
 
The base salaries were determined for Mr. Brumley, Mr. Arms and Ms. Weimer at the time of Enduro Sponsor’s formation in early 2010 and for Mr. Pardue and Mr. Grahek at the time of their commencement of employment with Enduro Sponsor in May 2010 and July 2010, respectively. None of Enduro Sponsor’s named executive officers received any base salary increases during 2010.
 
Discretionary Cash Bonus Awards.  A significant portion of the compensation for the named executive officers consists of an annual discretionary cash bonus award. Discretionary cash bonus awards are paid to link a substantial portion of compensation to annual performance and thereby encourage the named executive officers to create value for Enduro Sponsor’s members.
 
Cash bonus awards are based upon the Enduro Sponsor Board’s evaluation of company and individual performance without reference to specific goals, targets or levels of achievement. Whether any bonuses are paid, and the relative amounts of any such payments made, to the named executive officers is determined in the sole discretion of the Enduro Sponsor Board, taking into account the Enduro Sponsor Board’s subjective evaluation of company and individual performance based upon such factors as Enduro Sponsor’s success throughout the applicable year and the Enduro Sponsor Board’s view of a named executive officer’s scope of duties and ability to influence, and contribute to, Enduro Sponsor’s success throughout the applicable year.
 
When determining whether to award cash bonuses for 2010, and the relative amounts of any such awards, the Enduro Sponsor Board primarily considered the efforts of the named executive officers that culminated in Enduro Sponsor’s successful acquisition of the Predecessor Properties in December 2010 from Denbury Resources Inc. and the efforts of the named executive officers during 2010 in connection with the transactions by which Enduro Sponsor acquired the Acquired Properties in January 2011 and February 2011 from Samson Investment Company and ConocoPhillips Company, respectively. In light of these achievements, and based upon the foregoing considerations, the Enduro Sponsor Board determined to award bonuses for 2010 to each of the named executive officers in the amounts set forth in the Bonus column of the Summary Compensation Table below.
 
Long-Term Equity-Based Compensation Awards.  The named executive officers received equity-based compensation awards, in the form of Class B units of Enduro Sponsor, at the time they began employment with Enduro Sponsor in 2010. The Class B units represent profits interests in Enduro Sponsor and entitle the named executive officers to share in distributions by Enduro Sponsor above specified levels. For this reason and because on the date of grant Enduro Sponsor did not have operations or oil and natural gas assets, Enduro Sponsor determined that the fair value of the Class B units on the grant date was nominal.
 
The Class B units were granted subject to certain time-based forfeiture restrictions, which generally lapse at such times as described in “— Potential Payments upon Termination or Change-in-Control” below. The Enduro Sponsor Board believes that the grants of Class B units to the


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named executive officers encourages performance over the long term and provides the named executive officers with meaningful incentives to increase value to the members over time.
 
Additional Benefits
 
During 2010, Enduro Sponsor did not sponsor or maintain any employee benefit plans, and no named executive officer received any employee benefits or perquisites in 2010. Beginning in January 2011, Enduro Sponsor established certain retirement, health and welfare benefit plans in which the named executive officers are eligible to participate. The Enduro Sponsor Board believes the employee benefits that Enduro Sponsor began providing to the named executive officers in 2011 conform to industry standards and help to maintain the compensation of the named executive officers at competitive levels.
 
Employment and Severance Arrangements
 
The Enduro Sponsor Board considers the maintenance of a sound management team to be essential to protecting and enhancing the best interests of Enduro Sponsor and its members. To that end, the Enduro Sponsor Board recognizes that the uncertainty which may exist among the named executive officers with respect to their “at-will” employment may result in their departure or distraction to the detriment of Enduro Sponsor and its members. Accordingly, the Enduro Sponsor Board has determined that severance arrangements are appropriate to encourage the continued attention and dedication of certain named executive officers and to allow them to focus on the value to members of strategic alternatives without concern for the impact on their continued employment. Enduro Sponsor has entered into an employment agreement with each of Mr. Brumley, Mr. Arms, Ms. Weimer and Mr. Pardue that provides for severance benefits upon certain terminations of employment. The employment agreements, as described below, are substantially identical for each of the applicable named executive officers.
 
The employment agreements have initial terms of three years and are extended automatically for successive twelve-month periods thereafter unless either party delivers a written notice of non-renewal not less than sixty days prior to the expiration of the then-current employment term. The employment agreements provide that upon termination of a named executive officer’s employment either by Enduro Sponsor for convenience or due to the named executive officer’s resignation for good reason, subject to the timely execution of a general release of claims, the named executive officer is entitled to receive an amount equal to one times the named executive officer’s annual base salary plus one times the named executive officer’s annual bonus for the year prior to the year in which the termination occurs (or the named executive officer’s 2010 target bonus if the termination occurs in 2010). The severance amount is payable 50% in a lump-sum on the 60th day following the termination of employment and 50% in equal installments thereafter for one year, in accordance with Enduro Sponsor’s regular payroll practices.
 
As used in the employment agreements, a termination for “convenience” means an involuntary termination for any reason or no reason at all, other than a termination for “cause.” “Cause” is defined in the employment agreements to mean a named executive officer’s (i) having engaged in conduct that is or is reasonably expected to be materially injurious to Enduro Sponsor or its affiliates; (ii) material breach of the employment agreement; (iii) having been convicted of, or having entered a plea bargain or settlement admitting guilt for, any felony or engaging in fraudulent or criminal activity relating to the scope of the named executive officer’s employment (whether or not prosecuted); (iv) having been the subject of any order, judicial or administrative, obtained or issued by the Securities and Exchange Commission for any securities violation involving fraud on the part of the named executive officer; (v) material violation of Enduro Sponsor’s business conduct policies or any restrictive covenants with Enduro Sponsor; (vi) gross negligence or material misconduct in the performance of duties and services required of the named executive officer; or (vii) continuing and repeated failure to perform the duties as reasonably requested by Enduro Sponsor and within the reasonable scope of the named executive officer’s duties, other than as a result of incapacity.


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“Good reason” is defined in the employment agreements to mean a termination of employment by a named executive officer after (i) any material reduction in the named executive officer’s position or job responsibilities, (ii) the assignment of duties materially inconsistent with the named executive officer’s position or job responsibilities in the 90 days preceding the assignment, (iii) a material reduction in the named executive officer’s base salary, (iv) the relocation of the named executive officer’s principal place of employment more than 50 miles from its prior location, or (v) any other material breach by Enduro Sponsor of any agreement with the named executive officer.
 
Mr. Grahek is not party to an employment agreement with Enduro Sponsor and would not be entitled to any severance benefits upon a termination of employment.
 
Summary Compensation Table for 2010
 
The following table sets forth certain information with respect to the compensation paid to the named executive officers for 2010.
 
                                         
Name and
                             
Principal Position
  Year     Salary(1)     Bonus(2)     Unit Awards(3)     Total  
 
Jon S. Brumley
    2010     $ 236,528     $ 162,500           $ 399,028  
President and Chief Executive Officer
                                       
John W. Arms
    2010     $ 236,528     $ 162,500           $ 399,028  
Executive Vice President and Chief Operating Officer
                                       
Kimberly A. Weimer
    2010     $ 120,083     $ 82,500           $ 202,583  
Vice President and Chief Financial Officer
                                       
Bill R. Pardue
    2010     $ 103,125     $ 57,750           $ 160,875  
Director, Engineering and Operations
                                       
David J. Grahek
    2010     $ 72,558     $ 57,750           $ 130,308  
Director, Geology
                                       
 
 
(1) Amounts shown represent the base salary amounts paid to the named executive officers for service to Enduro Sponsor in 2010 and reflect the partial year of service following the named executive officers’ commencement of service with Enduro Sponsor in 2010. For each named executive officer’s annualized base salary amount, refer to the discussion above in “— Elements of Compensation — Base Salary.”
 
(2) Represents the discretionary cash bonus awards paid for 2010. For a discussion of the determination of these amounts, see “— Elements of Compensation — Discretionary Cash Bonus Awards.”
 
(3) The named executive officers each received an award of Class B units in the amounts set forth in the Grants of Plan-Based Awards for 2010 table below upon commencing employment. The grant date fair value of these awards was nominal and a value of $0 was assigned for purposes of the above table.


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Grants of Plan-Based Awards for 2010
 
The following table provides information regarding plan-based awards granted to the named executive officers for 2010.
 
                         
          All Other Unit
    Grant Date Fair
 
          Awards: Number of
    Value of Units
 
Name
  Grant Date     Units     Awards(1)  
 
Jon S. Brumley
    4/9/2010       32,500        
John W. Arms
    4/9/2010       32,500        
Kimberly A. Weimer
    4/9/2010       5,000        
Bill R. Pardue
    5/17/2010       5,000        
David J. Grahek
    7/23/2010       5,000        
 
 
(1) The Class B units had a nominal value as of the grant date.
 
Outstanding Equity Awards at December 31, 2010
 
The following table provides information regarding the Class B units in Enduro Sponsor held by the named executive officers as of December 31, 2010.
 
                 
    Unit Awards  
    Number of
    Market Value of
 
    Class B Units
    Class B Units
 
    That Have Not
    That Have Not
 
Name
  Vested(1)     Vested(2)  
 
Jon S. Brumley
    32,500        
John W. Arms
    32,500        
Kimberly A. Weimer
    5,000        
Bill R. Pardue
    5,000        
David J. Grahek
    5,000        
 
 
(1) Represents the number of Class B units of Enduro Sponsor that remained subject to a risk of forfeiture as of December 31, 2010. The risk of forfeiture with respect to Class B units held by the named executive officers generally lapses only at such times as described in “— Potential Payments upon Termination or Change-in-Control.”
 
(2) As described in footnote 3 to the Summary Compensation Table for 2010 and in “— Elements of Compensation — Long-Term Equity-Based Compensation Awards,” above, Class B units represent profits interests in Enduro Sponsor and entitle the named executive officers to share in distributions by Enduro Sponsor once the holders of Class A units of Enduro Sponsor have received distributions equal to their contributed capital amounts. Enduro Sponsor estimates that the value of the Class B units as of December 31, 2010 was nominal, assuming a liquidation of Enduro Sponsor’s assets and the distribution of all proceeds to Enduro Sponsor’s members.
 
Options Exercised and Units Vested
 
None of the named executive officers became vested in unit awards during 2010.
 
Pension Benefits for 2010
 
The named executive officers do not participate in any pension plans and did not receive or accrue any pension benefits during 2010.
 
Nonqualified Deferred Compensation
 
The named executive officers do not participate in any nonqualified deferred compensation plans and did not receive any nonqualified deferred compensation during 2010.


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Potential Payments upon Termination or Change-in-Control
 
Enduro Sponsor has entered into an employment agreement with each of Mr. Brumley, Mr. Arms, Ms. Weimer and Mr. Pardue that provides for severance benefits upon certain terminations of employment. Mr. Grahek is not party to an employment agreement with Enduro Sponsor and would not be entitled to any severance benefits upon a termination of employment. Please see “— Employment and Severance Arrangements.” Except as otherwise described below with regard to the Class B units, none of the named executive officers is entitled to any payments or benefits as a result of a change in control with respect to Enduro Sponsor. Assuming a termination of employment effective as of December 31, 2010 by Enduro Sponsor for convenience or due to a named executive officer’s resignation for good reason, the named executive officers (other than Mr. Grahek) would have received the following severance payments and benefits:
 
                 
          Termination for Convenience or Due to
 
Name
  Payment Type     Resignation for Good Reason ($)(1)  
 
Jon S. Brumley
    Salary       325,000  
      Bonus       162,500  
                 
      Total     $ 487,500  
John W. Arms
    Salary       325,000  
      Bonus       162,500  
                 
      Total     $ 487,500  
Kimberly A. Weimer
    Salary       165,000  
      Bonus       82,500  
                 
      Total     $ 247,500  
Bill R. Pardue
    Salary       165,000  
      Bonus       57,750  
                 
      Total     $ 222,750  
 
 
(1) The employment agreements between Enduro Sponsor and the applicable named executive officers provide that the named executive officers would be entitled to receive one times their target annual bonuses for 2010 in the event of a termination of employment during 2010 by Enduro Sponsor for convenience or resignation by the named executive officer for good reason. No target bonuses were communicated to the named executive officers for 2010. The amounts shown as “bonus” in this column equal the actual bonus amounts paid to the named executive officers for 2010.
 
The Class B units held by the named executive officers are subject to forfeiture in the event of certain terminations of employment with Enduro Sponsor. The forfeiture restrictions lapse based upon the passage of time or the occurrence of certain events, depending upon the circumstances of the applicable termination of employment. Generally, the forfeiture restrictions will lapse in the following amounts in the following scenarios:
 
Resignation for Good Reason or Termination Without Cause or Due to Death or Disability.  If a named executive officer’s employment is terminated by Enduro Sponsor without cause, by the named executive officer for good reason or due to the death or disability of the named executive officer, the forfeiture restriction will lapse (i) with respect to one-third of the named executive officer’s Class B units if the termination occurs after the one-year anniversary of the date of grant of the Class B units but before the two-year anniversary of such date; (ii) with respect to two-thirds of the named executive officer’s Class B units if the termination occurs after the two-year anniversary of the date of grant of the Class B units but before the three-year anniversary of such date and (iii) with respect to all of the named executive officer’s Class B units if the termination occurs after the three-year anniversary of the date of grant of the Class B units.


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Resignation Without Good Reason.  The forfeiture restrictions will lapse with respect to all of a named executive officer’s Class B units if the named executive officer resigns without good reason after (i) the occurrence of a “trigger event” (as described below) or the time at which the holders of Class A units of Enduro Sponsor have contributed, and had returned, their full capital commitments and (ii) at least 18 months have elapsed since the named executive officer began employment with Enduro Sponsor. The forfeiture restrictions will lapse with respect to one-third of a named executive officer’s Class B units if the named executive officer resigns without good reason (i) after the third anniversary of the date of grant of the Class B units, (ii) before the occurrence of a trigger event and (iii) before the time at which the holders of Class A units of Enduro Sponsor have contributed, and had returned, their full capital commitments.
 
Termination for Cause.  If the named executive officer’s employment is terminated for cause the forfeiture restrictions will not lapse with respect to any of the named executive officer’s Class B units, and all such units will be forfeited.
 
Cause and good reason in this context have the same meanings as in the named executive officers’ employment agreements, except that, with respect to Mr. Grahek, good reason does not include a relocation of his principal place of employment. A “trigger event” means the consummation of (i) a change in control, (ii) a public offering of Enduro Sponsor or one of its subsidiaries in which (a) at least 30% of the outstanding equity securities of Enduro Sponsor or at least 40% of the outstanding equity securities of one of Enduro Sponsor’s subsidiaries is sold in the offering and (b) the market value of the securities sold in the offering, if distributed to the holders of Class A units of Enduro Sponsor, would be at least equal to their contributed and unreturned capital amounts or (iii) any other event determined by the Enduro Sponsor Board to constitute a trigger event. “Change in control” means (i) the acquisition by a person or group of more than 50% of the total combined voting power of Enduro Sponsor’s outstanding securities or (ii) the consummation of a merger, consolidation, reorganization or business combination involving Enduro Sponsor, the sale of a substantial majority of all of Enduro Sponsor’s assets or the acquisition of assets or stock of another entity, in each case, other than a transaction which results in Enduro Sponsor’s voting securities before such transaction continuing to represent or being converted into a majority of the voting securities of the surviving entity.
 
Assuming the named executive officers had terminated employment with Enduro Sponsor as of December 31, 2010, or a change in control had occurred as of such date, none of the forfeiture restrictions with respect to the Class B units held by the named executive officers would have lapsed under any termination scenario.
 
Director Compensation For 2010
 
Enduro Sponsor does not pay cash compensation to any of the members of the Enduro Sponsor Board. Officers, employees and paid consultants or advisors of Enduro Sponsor or its principal unitholders who also serve as members of the Enduro Sponsor Board do not receive additional compensation of any kind for their service as directors. In 2010, Enduro Sponsor granted 5,000 Class B units in Enduro Sponsor to Mr. I. Jon Brumley in connection with Enduro Sponsor’s formation and Mr. I. Jon Brumley’s commencement of service on the Enduro Sponsor Board. The Class B units granted to Mr. I. Jon Brumley in 2010 had a nominal grant date fair value.
 
Litigation
 
Enduro Sponsor is not a party to any material legal action.
 
Indemnification
 
Subject to specified limitations, each member, manager and officer will not be liable, responsible or accountable in damages or otherwise to Enduro Sponsor or its members for, and Enduro Sponsor will indemnify and hold harmless each member, manager and officer from, any costs,


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expenses, losses or damages (including attorneys’ fees and expenses, court costs, judgments and amounts paid in settlement) incurred by reason of such person being a member, manager or officer of Enduro Sponsor.
 
Selected Historical and Unaudited Pro Forma Financial Data of Enduro Sponsor
 
The selected historical audited financial data presented below should be read in conjunction with the accompanying financial statements and related notes included elsewhere in this prospectus. The selected historical audited financial data of the Predecessor as of December 31, 2009 and 2010 and for each of the years in the three-year period ended December 31, 2010 have been derived from the Predecessor’s audited financial statements. Operations of the Predecessor Properties are deemed to be the “predecessor” of Enduro Sponsor and recorded transactions are shown separately based on the ownership of the Predecessor Properties. EAC owned the Predecessor Properties prior to March 9, 2010, at which time Denbury Resources Inc. acquired the properties in connection with its acquisition of EAC. Enduro Sponsor then acquired the Predecessor Properties on December 1, 2010. Accordingly, the audited financial statements of the Predecessor as of and for three years ended December 31, 2010 are presented for (i) “Predecessor-EAC” for the years ended December 31, 2008 and 2009 and for the period from January 1, 2010 through March 8, 2010; (ii) “Predecessor-DNR” for the period from March 9, 2010 through November 30, 2010 and (iii) “Enduro Sponsor” for the period from Enduro Sponsor’s inception (March 3, 2010) through December 31, 2010.
 
The selected historical unaudited financial data of Enduro Sponsor as of March 31, 2011 and 2010 and for the three-month period ended March 31, 2011 and 2010 have been derived from Enduro Sponsor’s unaudited interim financial statements. The unaudited financial statements were prepared on a basis consistent with the audited statements and, in the opinion of Enduro Sponsor’s management, include all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the results of Enduro Sponsor for the periods presented.
 
The selected unaudited pro forma financial data for the three months ended March 31, 2011 and for the year ended December 31, 2010 set forth in the following table has been derived from the unaudited pro forma financial statements of Enduro Sponsor included in this prospectus beginning on page ENDURO F-1. The pro forma adjustments have been prepared as if the acquisition of the Acquired Properties and, with respect to the pro forma as adjusted information, the conveyance of the Net Profits Interest, the offer and sale of the trust units and application of the net proceeds therefrom, had taken place (i) on March 31, 2011, in the case of the pro forma balance sheet information as of March 31, 2011, and (ii) as of January 1, 2010, in the case of the pro forma statements of earnings for the three months ended March 31, 2011 and for the year ended December 31, 2010.
 


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    Enduro
    Enduro Sponsor
                                                 
    Sponsor
    Pro Forma
    Enduro
    Enduro Sponsor
                                     
    Pro Forma
    as Adjusted
    Sponsor
    Pro Forma
                                     
    for the
    for the Offering
    Pro Forma
    as Adjusted
                                           
    Acquisition
    (including the
    for the
    for the Offering
                                           
    of the
    Conveyance of the
    Acquisition
    (including the
    Enduro Sponsor               Predecessor —
                     
    Acquired
    Net Profits
    of the
    Conveyance of the
          March 3,
              DNR       Predecessor — EAC  
    Properties     Interest)     Acquired
    Net Profits
          2010
      Enduro Sponsor       March 9,
      January 1,
             
    Three Months
    Three Months
    Properties     Interest)     Three Months
    (Inception)
      Inception
      2010
      2010
             
    Ended
    Ended
    Year Ended
    Year Ended
    Ended
    Through
      Through
      Through
      Through
    Year Ended
 
    March 31,
    March 31,
    December 31,
    December 31,
    March 31,
    March 31,
      December 31,
      November 30,
      March 8,
    December 31,  
    2011     2011     2010     2010     2011     2010       2010       2010       2010     2009     2008  
(In thousands)   (Unaudited)     (Unaudited)     (Unaudited)     (Unaudited)     (Unaudited)     (Unaudited)                                      
Revenues
                                                                                             
Oil
  $ 20,202     $ 18,643     $ 70,161     $ 63,219     $ 10,236     $       $ 106       $ 1,036       $ 331     $ 1,909     $ 3,295  
Natural Gas
    12,774       12,212       62,420       59,071       11,899               3,486         35,503         10,756       31,998       59,075  
Marketing
    817       817       5,131       5,131       817               383         3,671         1,077              
                                                                                               
Total revenues
  $ 33,793     $ 31,672     $ 137,712     $ 127,421     $ 22,952     $       $ 3,975       $ 40,210       $ 12,164     $ 33,907     $ 62,370  
Expenses
                                                                                             
Lease operating
  $ 6,827     $ 6,827     $ 27,019     $ 27,019     $ 4,007     $       $ 507       $ 5,285       $ 1,142     $ 7,608     $ 6,343  
Production, ad valorem, and severance taxes
    2,330       2,330       9,417       9,417       1,447               170         2,003         548       2,565       2,442  
Gathering and transportation
    835       835       3,845       3,845       794               206         2,755         429       2,138       2,577  
Depletion, depreciation, and amortization
    14,793       11,157       64,723       49,341       10,830               1,973         21,754         7,949       33,665       26,716  
Exploration expense
                10,188       10,188                             9,957         231       8,688       723  
Marketing
    795       795       5,020       5,020       795               372         3,588         1,060              
General and administrative
    3,506       3,506       11,742       11,742       3,043       77         3,826         1,254         2,481       5,045       4,001  
Merger-related transaction costs
                                                      6,922         16,136              
Derivative fair value loss
    11,449       11,449       4,977       4,977       11,449               4,977                              
Other operating
    1,033       1,033       960       960       896               18         24         9       51       28  
                                                                                               
Total expenses
  $ 41,568     $ 37,932     $ 137,891     $ 122,509     $ 33,261     $ 77       $ 12,049       $ 53,542       $ 29,985     $ 59,760     $ 42,830  
                                                                                               
Operating income (loss)
  $ (7,775 )   $ (6,260 )   $ (179 )   $ 4,912       (10,309 )     (77 )     $ (8,074 )     $ (13,332 )     $ (17,821 )   $ (25,853 )   $ 19,540  
                                                                                               
Interest expense, net
  $ (1,818 )   $ (375 )   $ (8,466 )   $ (1,995 )     (1,220 )           $ (148 )     $ (6,183 )     $     $     $  
Deferred income tax benefit
  $ 34     $ 34     $     $     $ 34     $       $       $       $     $     $  
                                                                                               
Net income (loss)
  $ (9,559 )   $ (6,601 )   $ (8,645 )   $ 2,917     $ (11,495 )   $ (77 )     $ (8,222 )     $ (19,515 )     $ (17,821 )   $ (25,853 )   $ 19,540  
                                                                                               
                                                                                               
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations of Enduro Sponsor
 
You should read the following discussion of the financial condition and results of operations of Enduro Sponsor in conjunction with the historical consolidated financial statements and related notes included elsewhere in this prospectus.
 
For purposes of the following discussion in “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Enduro Sponsor,” all references herein to “Enduro Sponsor” are intended to mean the Predecessor without giving effect to the acquisition of the Acquired Properties. For more information about the presentation of the Predecessor financial statements, please see “Financial Statements of Enduro Sponsor — Enduro Resource Partners LLC Predecessor.”
 
Factors that Significantly Affect Enduro Sponsor’s Results
 
Enduro Sponsor’s revenue, cash flow from operations and future growth depend substantially on factors beyond its control, such as economic, political and regulatory developments and competition from producers of alternative sources of energy. Oil and natural gas prices have historically been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect Enduro Sponsor’s financial position, results of operations and ability to access capital, as well as the quantities of oil and natural gas that it can economically produce.
 
Like all businesses engaged in the exploration and production of oil and natural gas, Enduro Sponsor faces the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well decreases. Thus, an oil and gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. The operators of the Underlying Properties attempt to reduce this natural decline by undertaking field

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development programs and by implementing secondary recovery techniques. Their ability to make development expenditures to maintain production from existing reserves and to add reserves through development drilling is dependent on their capital resources and can be limited by many factors.
 
Results of Operations
 
Comparison of the Quarters Ended March 31, 2011 and 2010
 
Results of operations of Enduro Sponsor for the quarter ended March 31, 2011 include oil and natural gas properties since their relevant acquisition date, and therefore, results of the Denbury, Samson and ConocoPhillips acquisitions are included as of January 1, 2011, January 5, 2011 and February 28, 2011, respectively. Enduro Sponsor’s results of operations from March 9, 2010 (Inception) through March 31, 2010 do not include any oil and natural gas activities, as Enduro Sponsor did not acquire any oil and natural gas assets until December 1, 2010.
 
The following table shows a summary of Enduro Sponsor’s financial data for the periods indicated (in thousands):
 
                 
          March 3, 2010
 
    Three Months Ended
    (Inception) Through
 
    March 31, 2011     March 31, 2010  
    (Unaudited)  
 
Revenues
               
Oil
  $ 10,236     $  
Natural Gas
    11,899        
Marketing
    817        
                 
Total revenues
  $ 22,952     $  
Expenses
               
Lease operating
  $ 4,007     $  
Production, ad valorem, and severance taxes
    1,447        
Gathering and transportation
    794        
Depletion, depreciation, and amortization
    10,830        
Marketing
    795        
General and administrative
    3,043       77  
Derivative fair value loss
    11,449        
Other operating
    896        
                 
Total expenses
  $ 33,261     $ 77  
                 
Operating loss
    (10,309 )     (77 )
                 
Interest expense, net
    (1,220 )      
Deferred income tax benefit
    34        
                 
Net loss
  $ (11,495 )   $ (77 )
                 
Sales volumes:
               
Oil (MBbls)
    114        
Natural gas (MMcf)
    2,849        
Total sales (MBoe)
    589        
Average sales prices:
               
Oil (per Bbl)
  $ 89.79     $  
Natural gas (per Mcf)
  $ 4.18     $  
Average costs per Boe:
               
Lease operating
  $ 6.80     $  
Gathering and transportation
  $ 1.35     $  
Production and other taxes
  $ 2.46     $  


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Enduro Sponsor’s oil and natural gas revenues fluctuate based on commodity spot markets and changes in production volumes of oil and natural gas sold during a given period. Oil revenues for the three months ended March 31, 2011 were $10.2 million, or $89.79 per barrel, while there were no oil revenues or oil produced during the period from March 3, 2010 through March 31, 2010.
 
Natural gas revenues for the three months ended March 31, 2011 represent the $4.18 per Mcf received for 2,849 Mmcf natural gas produced during the period related to the Denbury, Samson and ConocoPhillips acquisitions.
 
Marketing revenues in the period ended March 31, 2011 represent the revenue received for natural gas sold to midstream companies but produced by others. Marketing revenues fluctuate based on volumes produced and prices received, similar to natural gas revenues.
 
Lease operating expenses were $4.0 million in the first quarter of 2011, or $6.80 per Boe.
 
Production, ad valorem, and severance taxes were $1.4 million during the three months ended March 31, 2011 and relate to monthly production taxes paid to Louisiana, Texas and New Mexico for oil and natural gas produced as well as ad valorem taxes that were incurred based on property values.
 
Gathering and transportation expenses were $0.8 million and relate to costs charged by operators for compression, gathering and transportation services related to oil and natural gas produced.
 
Depletion, depreciation, and amortization expense was $10.8 million in the first quarter of 2011 due to production volumes primarily relating to Enduro Sponsor’s acquisition of the Denbury assets.
 
Marketing expense was $0.8 million in the first quarter of 2011. These expenses were associated with production purchased at the wellhead related to the Denbury assets acquired in December 2010.
 
General and administrative expense increased to $3.0 million from $0.1 million in the period from March 3, 2010 through March 31, 2011. This increase resulted from the increased staffing related to managing assets acquired in December 2010, January 2011 and February 2011.
 
Derivative fair value loss of $11.4 million represents unrealized losses in fair values of commodity contracts of $11.8 million offset by $0.4 million in hedge settlements received. Enduro Sponsor entered into several oil and natural gas derivative contracts during the three months ended March 31, 2011 in connection with the acquisition of the ConocoPhillips Permian Basin assets. There were no such derivative instruments in place during the period from March 3, 2010 through March 31, 2010.
 
Interest expense was $1.2 million in the first quarter of 2011 due to Enduro Sponsor borrowing $233 million under its revolving credit facility (not including debt issuance cost of $3.4 million). The funds from these borrowings were used to purchase the Denbury East Texas/North Louisiana assets in December 2010. During the period from March 3, 2010 through March 31, 2010, there were no outstanding interest bearing loans.
 
Comparison of the Years Ended December 31, 2010 and 2009
 
Operations of the Predecessor Properties are deemed to be the “predecessor” of Enduro Sponsor and recorded transactions are shown separately based on the ownership of the Predecessor Properties. EAC owned the Predecessor Properties prior to March 9, 2010, at which time Denbury Resources Inc. acquired the properties in connection with its acquisition of EAC. Enduro Sponsor then acquired the Predecessor Properties on December 1, 2010. Accordingly, the audited financial statements of the Predecessor as of and for the year ended December 31, 2010 are presented for (i) “Predecessor-EAC” for the period from January 1, 2010 through March 8, 2010, (ii) “Predecessor-DNR” for the period from March 9, 2010 through November 30, 2010 and (iii) “Enduro Sponsor” for the period from Enduro Sponsor’s inception (March 3, 2010) through December 31, 2010.


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The following table shows a summary of Enduro Sponsor’s financial data for the periods indicated (in thousands):
 
                                     
    Enduro Sponsor       Predecessor - DNR       Predecessor - EAC  
    Inception
      March 9,
      January 1,
    Year
 
    Through
      2010 Through
      2010 Through
    Ended
 
    December 31,
      November 30,
      March 8,
    December 31,
 
    2010       2010       2010     2009  
Revenue
                                   
Oil
  $ 106       $ 1,036       $ 331     $ 1,909  
Natural gas
    3,486         35,503         10,756       31,998  
Marketing
    383         3,671         1,077        
                                     
Total Revenues
  $ 3,975       $ 40,210       $ 12,164     $ 33,907  
Expenses
                                   
Lease operating
  $ 507       $ 5,285       $ 1,142     $ 7,608  
Production, ad valorem and severance taxes
    170         2,003         548       2,565  
Gathering and transportation
    206         2,755         429       2,138  
Depletion, depreciation, and amortization
    1,973         21,754         7,949       33,665  
Exploration expense
            9,957         231       8,688  
Marketing
    372         3,588         1,060        
General and administrative
    3,826         1,254         2,481       5,045  
Merger related transaction costs
            6,922         16,136        
Derivative fair value loss
    4,977                        
Other operating
    18         24         9       51  
                                     
Total expenses
  $ 12,049       $ 53,542       $ 29,985     $ 59,760  
Operating income (loss)
    (8,074 )       (13,332 )       (17,821 )     (25,853 )
Interest expense, net
  $ (148 )     $ (6,183 )     $     $  
                                     
Net income (loss)
  $ (8,222 )     $ (19,515 )     $ (17,821 )   $ (25,853 )
                                     
Production Volumes
                                   
Oil (MBbls)
    1         14         5       35  
Natural Gas (MMcf)
    853         8,944         1,941       8,569  
Total (MBoe)
    143         1,505         329       1,463  
Average sales prices:
                                   
Oil ($/Bbl)
  $ 106.00       $ 74.00       $ 66.20     $ 54.54  
Natural gas ($/Mcf)
  $ 4.09       $ 3.97       $ 5.54     $ 3.73  
Average costs per Boe:
                                   
Lease operating
  $ 3.55       $ 3.51       $ 3.47     $ 5.20  
Production, ad valorem and severance taxes
  $ 1.19       $ 1.33       $ 1.67     $ 1.75  
Gathering and transportation
  $ 1.44       $ 1.83       $ 1.30     $ 1.46  
Depletion, depreciation, and amortization
  $ 13.80       $ 14.45       $ 24.16     $ 23.01  
 
Enduro Sponsor’s oil and natural gas revenues fluctuate based on the commodity spot market and changes in production volumes of oil and natural gas sold during a given period. Oil revenues were lower for all periods presented in 2010 than in 2009 mainly due to a decline in volume sold slightly offset by an increase in the average prices per barrel of oil received, which were $106 in the


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period from December 1, 2010 through December 31, 2010, $74.00 in the period from March 9, 2010 through November 30, 2010 and $66.20 for the period from January 1, 2010 through March 8, 2010, as compared to $54.54 during 2009.
 
Natural gas revenues increased by 36%, to $49.7 million, during all 2010 periods presented due to increased production volume and an increase in average prices received. Approximately $11.8 million of this increase was attributable to higher volumes sold while approximately $6.0 million of this increase was due to a $.50 per Mcf increase in the average realized natural gas price.
 
Marketing revenues relate to production purchased at the wellhead and sold to midstream companies. There were no marketing revenues in 2009 since the transaction relates to production of wells drilled in 2009. The price received is recorded in marketing revenue and the price paid to purchase commodities is recorded in marketing expense.
 
Lease operating expense decreased as ownership of the wells changed hands. Lease operations expense was $5.20 per Boe during 2009 while it was $3.55 in December 2010, $3.51 from March 9, 2010 through November 30, 2010 and $3.47 from January 1, 2010 through March 8, 2010. Lease operating expense decreased by $0.7 million, of which $3.3 million was due to lower rate, offset by a $2.6 million increase due to higher production volume.
 
Gathering and transportation expense increased by $1.3 million when comparing all periods presented in 2010 to the year ended December 31, 2009. This increase was mainly due to an increase in volumes of oil and natural gas and an increase in gathering fee per Mcf.
 
Depletion, depreciation, and amortization expense recognized was lower during all periods presented in 2010 than in 2009 due to a decline in depletion, depreciation, and amortization expense per barrel (DD&A rate) offset by an increase in production volumes. The DD&A rate is a function of the amount paid for the underlying assets and reserves recognized. The DD&A rate was $13.80 for the period from December 1, 2010 through December 31, 2010, $14.45 for March 9, 2010 through November 30, 2010 and $24.16 from January 1, 2010 through March 8, 2010, and it was $23.01 per Bbl during 2009.
 
Exploration expense in 2009 primarily related to expense recognized for three unproductive exploratory wells drilled, while exploration expense from January 1, 2010 through March 8, 2010 related to acreage costs ratably amortized. From March 9, 2010 to November 30, 2010 the amortization of unproved properties increased due to the fair value step up in the basis of the unproved properties recognized during purchase price allocation of Denbury’s merger with EAC.
 
General and administrative expense relates to office personnel and corporate costs incurred. The predecessor amounts were allocated while Enduro’s general and administrative expenses are recognized based on actual invoices received and services performed from March 3, 2010 through December 31, 2010. These costs were generally higher in 2010 as a result of Denbury’s merger with EAC and the acquisition of the Denbury properties.
 
Merger related costs relate to Denbury’s merger with EAC. EAC’s severance and transaction costs were allocated to the East Texas/North Louisiana properties based on relative production volumes.
 
Derivative fair value loss represents the change in fair value of Enduro Sponsor’s commodity contracts from October 2010 through December 31, 2010.
 
Interest expense recognized in the period from March 8, 2010 through November 30, 2010 represents interest on debt attributed to Denbury’s merger with EAC.


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Comparison of the Years Ended December 31, 2009 and 2008
 
The following table shows a summary of Enduro Sponsor’s financial data for the periods indicated (in thousands):
 
                 
    Predecessor - EAC  
    Year Ended December 31,  
    2009     2008  
 
Revenue
               
Oil
  $ 1,909     $ 3,295  
Natural gas
    31,998       59,075  
                 
Total Revenues
  $ 33,907     $ 62,370  
Expenses
               
Lease operating
  $ 7,608     $ 6,343  
Production, ad valorem and severance taxes
    2,565       2,442  
Gathering and transportation
    2,138       2,577  
Depletion, depreciation, and amortization
    33,665       26,716  
Exploration expense
    8,688       723  
General and administrative
    5,045       4,001  
Other operating
    51       28  
                 
Total expenses
  $ 59,760     $ 42,830  
                 
Net income (loss)
  $ (25,853 )   $ 19,540  
                 
Production Volumes
               
Oil (MBbls)
    35       36  
Natural Gas (MMcf)
    8,569       6,946  
Total (MBoe)
    1,463       1,193  
Average realized prices
               
Oil ($/Bbl)
  $ 54.54     $ 91.53  
Natural gas ($/Mcf)
  $ 3.73     $ 8.50  
Selected Expenses (per Boe):
               
Lease operating
  $ 5.20     $ 5.32  
Production, ad valorem and severance taxes
  $ 1.75     $ 2.05  
Gathering and transportation
  $ 1.46     $ 2.16  
Depletion, depreciation, and amortization
  $ 23.01     $ 22.39  
 
Enduro Sponsor’s oil and natural gas revenues fluctuate based on the commodity spot market prices and production volumes sold during the period. Oil revenues realized during 2009 were lower than in 2008 due to a decline in prices received. Average prices received during the year ended December 31, 2009 were $54.54 per barrel while they were $91.53 in the year ended December 31, 2008.
 
Natural gas revenues decreased 45.8%, or $27.1 million, due to a decrease in average prices received offset by an increase in production. The higher volumes increased natural gas revenue by approximately $6.0 million while the $4.77 per Mcf decrease in average realized oil price decreased natural gas revenues by approximately $33.1 million and was primarily due to a lower average NYMEX price.
 
Lease operating expense increased mainly due to higher production volume, offset by a $0.12 per Boe decrease in lease operating expense.


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Gathering and transportation expense decreased by $0.4 million in the year ended December 31, 2009 when compared to the year ended December 1, 2008. This decrease was mainly due to a decrease in gathering fee per Mcf slightly offset by an increase in production.
 
Depletion, depreciation, and amortization expense recognized increased during 2010 due to an increase in depletion, depreciation, and amortization expense per barrel and an increase in production volumes.
 
Exploration expense in 2009 primarily related to expenses recognized related to three unproductive exploratory wells drilled while exploration expense recognized for the year ended December 31, 2008 related to acreage costs ratably amortized.
 
General and administrative expenses remained relatively flat on a per boe basis.
 
Liquidity and Capital Resources
 
Enduro Sponsor’s primary sources of capital and liquidity have been proceeds from members’ contributions, borrowings under its revolving credit facility and cash flow from operations. To date, primary uses of capital have been to acquire and develop oil and natural gas properties located in Texas, Louisiana and New Mexico. Enduro Sponsor continually monitors its capital resources available to meet its future financial obligations and planned development expenditures.
 
Enduro Sponsor’s outstanding indebtedness increased to $233 million by March 31, 2011. Historically, Enduro Sponsor has not had any indebtedness and, therefore, did not have interest expense. In order to fund a portion of the purchase price for the Denbury assets in December 2010, the Samson assets in January 2011 and the ConocoPhillips assets in February 2011, Enduro Sponsor borrowed $233 million under the revolving credit facility (excluding $3.4 million of debt issuance costs). As of March 31, 2011, the revolving credit facility bore interest at a rate of 2.5% to 3.1% per annum. The Company’s weighted average of total indebtedness in the first quarter of 2011 was 3.0%. Enduro Sponsor plans to use a portion of the net proceeds from this offering to repay some of the outstanding borrowings under the revolving credit facility. In addition, any additional borrowings will increase interest expense during the period they are outstanding.
 
Cash Flows from Operating Activities
 
Enduro Sponsor’s net cash used in operating activities was $13.1 million for the period from Inception (March 3, 2010) through December 31, 2010 and net cash used in operating activities was $11.6 million for the first quarter 2011. Oil and natural gas production is the primary source of cash provided by operating activities. Payments made for the operation of oil and natural gas properties and for general corporate purposes are the primary uses of cash for operating activities.
 
Enduro Sponsor’s cash flow from operations is subject to many variables, the most significant of which are oil and natural gas prices. Oil and natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond its control. Enduro Sponsor’s future cash flow from operations will depend on its ability to maintain and increase production through its development program, as well as the prices of oil and natural gas. See “Quantitative and Qualitative Disclosure about Market Risk — Commodity Price Risk.”
 
Cash Flows from Investing Activities
 
Enduro Sponsor’s development expenditures were $2.6 million for the period of December 1, 2010 through December 31, 2010. During the three months ended March 31, 2011 Enduro Sponsor paid $1.6 million for development activities and $401.0 million for acquisition of oil and natural gas assets.


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Enduro Sponsor currently anticipates that its development budget, which predominantly consists of workover drilling and development drilling, will be $52 million for 2011. The amount and timing of its development expenditures is largely discretionary and within its control. Enduro Sponsor routinely monitors and adjusts its development expenditures in response to changes in oil and natural gas prices, development expenses, industry conditions and internally generated cash flow. Future cash flows are subject to a number of variables, including the level of production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of development expenditures.
 
Cash Flows from Financing Activities
 
In December 2010, Enduro Sponsor entered into a five-year senior secured credit agreement with a bank syndicate comprised of Bank of America, N.A. and other lenders. The Credit Agreement matures in December 2015. The Credit Agreement provides for revolving credit loans to be made to Enduro Sponsor from time to time and letters of credit to be issued to Enduro Sponsor. The aggregate amount of loan commitments of the lenders under the Credit Agreement is $500 million. Availability under the Credit Agreement is subject to a borrowing base of $250 million as of February 28, 2011, which is redetermined semi-annually in May and November and upon requested special redeterminations. The borrowing base is adjusted at the banks’ discretion and is based in part upon external factors over which Enduro Sponsor has no control. As of June 30, 2011, there was $231 million in outstanding borrowings and $19 million of borrowing capacity under the Credit Agreement.
 
Enduro Sponsor incurs a commitment fee of 0.5% on the unused portion of the credit facility.
 
Loans under the Credit Agreement are subject to varying rates of interest based on (i) the total outstanding borrowings in relation to the borrowing base and (ii) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin of 1.75% to 2.75% based on the ratio of outstanding borrowings to the borrowing base, and base rate loans bear interest at the base rate plus the applicable margin of 0.75% to 1.75% based on the ratio of outstanding borrowings to the borrowing base. The “Eurodollar rate” for any interest period (either one, two, three or six months, as selected by Enduro Sponsor or such longer period of up to twelve months as selected by Enduro Sponsor and consented to by the lenders) is the rate per year equal to the London Interbank Offered Rate (“LIBOR”), as published by Reuters or another source designated by Bank of America, N.A. for deposits in dollars for a similar interest period. The “base rate” is calculated as the highest of (i) the annual rate of interest announced by Bank of America, N.A. as its “prime rate,” (ii) the federal funds effective rate plus 0.5% and (iii) the Eurodollar Rate (as defined in the Credit Agreement) for a one-month interest period plus 1.0%.
 
The Credit Agreement is secured by substantially all of the proved oil and natural gas properties of Enduro Sponsor and its subsidiaries.
 
The Credit Agreement contains several restrictive covenants including, among others:
 
  •      a prohibition against incurring debt, subject to permitted exceptions;
 
  •      a restriction on creating liens on the assets of Enduro Sponsor, subject to permitted exceptions;
 
  •      restrictions on merging and selling assets outside the ordinary course of business;
 
  •      a requirement to maintain a ratio of consolidated current assets to current liabilities (as defined in the Credit Agreement) of not less than 1.0 to 1.0; and
 
  •      a requirement that Enduro Sponsor maintain a ratio of debt to annualized adjusted EBITDA (as defined in the Credit Agreement) of not more than 4.0 to 1.0, commencing with the quarter ending March 31, 2011.


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Additionally, there is a limitation on the aggregate amount of forecasted oil and natural gas production that can be economically hedged with oil or natural gas derivative contracts.
 
The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the Credit Agreement to be immediately due and payable. At December 31, 2010, Enduro Sponsor was in compliance with all of its debt covenants.
 
Contractual Obligations
 
A summary of Enduro Sponsor’s contractual obligations as of December 31, 2010 is provided in the following table.
 
                                         
    Payments Due by Period  
          Less Than
                More Than
 
    Total     1 Year     1-3 Years     3-5 Years     5 Years  
                (In thousands)              
 
Long-term debt(1)
  $ 52,000     $     $     $ 52,000     $  
Transportation agreement
  $ 22,385     $ 2,464     $ 7,398     $ 7,398     $ 5,125  
Lease agreements
  $ 3,072     $ 287     $ 1,593     $ 1,192     $  
                                         
Total
  $ 77,457     $ 2,751     $ 8,991     $ 60,590     $ 5,125  
                                         
 
 
(1) The amounts included in the table above represent principal maturities only. See “— Quantitative and Qualitative Disclosure about Market Risk — Interest rate risk” for information regarding interest payment obligations under long-term debt obligations.
 
Off-Balance Sheet Arrangements
 
As of December 31, 2010, Enduro Sponsor had no off-balance sheet arrangements.
 
Critical Accounting Policies and Estimates
 
The discussion and analysis of Enduro Sponsor’s historical financial condition and results of operations is based upon its consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires it to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Enduro Sponsor evaluates its estimates and assumptions on a regular basis. It bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of its financial statements. Enduro Sponsor has provided below an expanded discussion of its more significant accounting policies, estimates and judgments. It believes these accounting policies reflect its more significant estimates and assumptions used in the preparation of its financial statements. Please read the notes to the financial statements of Enduro Sponsor included elsewhere in this prospectus for a discussion of additional accounting policies and estimates made by its management.
 
Oil and Natural Gas Properties
 
Enduro Sponsor follows the successful efforts method of accounting for its oil and natural gas properties. Under this method, all costs associated with productive and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical


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expenditures are expensed. Net capitalized costs of unproven property and exploration well costs are reclassified as proved property and well costs when related proved reserves are found.
 
Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive. If an exploration well is unsuccessful in finding proved reserves, the capitalized well costs are charged to exploration expense. Enduro Sponsor does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheet following the completion of drilling unless both of the following conditions are met:
 
(i) the well has found a sufficient quantity of reserves to justify its completion as a producing well, and
 
(ii) Enduro Sponsor is making sufficient progress in assessing the reserves and the economic and operating viability of the project.
 
Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable.
 
Costs of significant nonproducing properties and exploratory wells in progress of being drilled are excluded from depletion until such time as the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.
 
Enduro Sponsor reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. If an impairment loss is indicated by the carrying amount of the assets exceeding the sum of the undiscounted expected future net cash flows, then an impairment loss is recognized for the amount by which the carrying amount of the asset exceeds its estimated fair value. Estimates of the sum of expected future cash flows require management to estimate future recoverable proved and risk-adjusted probable and possible reserves, forecasts of future commodity prices, production and capital costs and discount rates. Uncertainties about these future cash flow variables cause impairment estimates to be inherently imprecise.
 
Unproved oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. The impairment assessment is affected by the results of exploration activities, commodity price outlooks, planned future sales, or expiration of all or a portion of such projects. If the quantity of potential reserves determined by such evaluation is not sufficient to fully recover the cost invested in each project, Enduro Sponsor will recognize an impairment loss at the time such determination is made.
 
Oil and Natural Gas Reserve Quantities
 
Enduro Sponsor’s estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Cawley Gillespie prepares a reserve and economic evaluation of all of Enduro Sponsor’s properties on a well-by-well basis.
 
Reserves and their relation to estimated future net cash flows impact Enduro Sponsor’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Enduro Sponsor prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve reports. The accuracy of its reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.


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Enduro Sponsor’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.
 
Revenue Recognition
 
Sales of oil and natural gas are recognized when such products have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable.
 
Enduro Sponsor sells oil and natural gas on a monthly basis. Virtually all of Enduro Sponsor’s contract pricing provisions are tied to a market index. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Accounts receivable — trade” in the Consolidated Balance Sheet.
 
Enduro Sponsor uses the sales method of accounting for oil and natural gas revenues, recognizing revenues based on the oil and natural gas delivered rather than its working interest share of oil and natural gas produced.
 
Enduro Sponsor had no material imbalances as of December 31, 2010.
 
Marketing revenues derived from sales of oil or natural gas purchased from third parties are recognized when persuasive evidence of a sales arrangement exists, delivery has occurred, the sales price is fixed or determinable and collectibility is reasonably assured. As Enduro Sponsor takes title to the oil and natural gas and has risks and rewards of ownership, these transactions are presented gross in marketing revenue and marketing expense in the Consolidated Statement of Operations, unless they meet the criteria for netting.
 
Derivatives
 
Enduro Sponsor uses derivative financial instruments to reduce exposure to commodity price fluctuations. These transactions are primarily in the form of swap contracts, put options and collars with large financial institutions, all of which are lenders underwriting Enduro Sponsor’s revolving credit facility.
 
Derivative instruments are recorded at fair value and included on the Consolidated Balance Sheet as assets or liabilities. Enduro Sponsor has not designated its derivative contracts as hedges for accounting purposes; therefore, all changes in fair value of the contracts are recorded in “Derivative fair value loss” in the Consolidated Statement of Operations.
 
Asset Retirement Obligations
 
Enduro Sponsor records a liability for the fair value of an asset retirement obligation in the period in which it is incurred. For oil and natural gas properties, this is the period in which the property is acquired or a new well is drilled. Asset retirement obligations are capitalized as part of the carrying values of the long-lived assets.
 
Asset retirement obligations are recorded at the present value of expected future net cash flows and are discounted using Enduro Sponsor’s credit adjusted risk free rate and then accreted until settled or sold, at which time the liability is reversed. Estimates are based on average plugging and abandonment well costs and estimated remaining field life based on reserve estimates.


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Recently Issued Accounting Pronouncements
 
The following discussion provides information about new accounting pronouncements:
 
In December 2008, the SEC released the final rule on “Modernization of Oil and Gas Reporting” (the “Reserve Ruling”). The Reserve Ruling revises oil and gas reporting disclosures. The Reserve Ruling also permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The Reserve Ruling will also allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor, (ii) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit and (iii) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price. The Reserve Ruling became effective for fiscal years ending on or after December 31, 2009. During December 2009, the FASB issued Accounting Standards Update No. 2010-03, “Extractive Activities — Oil and Gas (Topic 932),” (“ASU 2010-03”) to conform generally accepted accounting principles to the Reserve Ruling. The Company adopted the provisions of the Reserve Ruling and the provisions of ASU 2010-03 on December 3, 2009.
 
In September 2006, the FASB issued guidance to define fair value, establish a framework for measuring fair value and to enhance disclosures about fair value measures required under other accounting pronouncements. In January 2010, the FASB issued guidance to (i) require separate disclosure of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers, (ii) require separate disclosure of purchases, sales, issuances and settlements in the reconciliation for fair value measurements using significant unobservable inputs (Level 3), (iii) clarify the level of disaggregation for fair value measurements of assets and liabilities and (iv) clarify disclosures about inputs and valuation techniques used to measure fair values for both recurring and nonrecurring fair value measurements. The implementation did not have a material effect on the financial condition or results of operations of Enduro Sponsor’s financial statements.
 
Quantitative and Qualitative Disclosure about Market Risk
 
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about Enduro Sponsor’s potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how Enduro Sponsor views and manages its ongoing market risk exposures. All of its market risk sensitive instruments were entered into for purposes other than speculative trading.
 
Commodity Price Risk
 
Enduro Sponsor’s major market risk exposure is in the pricing applicable to its oil and natural gas production. Realized pricing is primarily driven by the spot market prices applicable to its oil production and the prevailing price for natural gas. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and Enduro Sponsor expects this volatility to continue in the future. The prices it receives for oil and natural gas production depend on many factors outside of its control.


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The following table sets forth the volumes involved in Enduro Sponsor’s natural gas commodity derivative contracts and the weighted-average contractual prices per Mcf as of March 31, 2011:
 
                                         
                            Fair Value
 
    Daily Put
    Average
    Daily Swap
    Average
    March 31,
 
Period   Volumes     Price     Volumes     Price     2011  
    (Mcf)     ($/Mcf)     (Mcf)     ($/Mcf)     (In thousands)  
 
April 2011 — December 2011
    14,000     $ 4.20       10,000     $ 4.30     $ 976  
January 2012 — December 2012
    14,000     $ 4.90       10,000     $ 4.57     $ 2,072  
January 2013 — December 2013
    12,000     $ 4.90       8,000     $ 5.00     $ 2,031  
                                         
                                    $ 5,079  
                                         
 
The following tables set forth the volumes involved in Enduro Sponsor’s oil commodity derivative contracts and the weighted-average NYMEX prices per Bbl as of March 31, 2011:
 
                                                                 
                      Average
    Average
                   
    Daily
    Average
    Daily
    Collar
    Collar
    Daily
          Fair Value
 
    Put
    Put
    Collar
    Put
    Cap
    Swap
    Average
    March 31,
 
Period   Volumes     Price     Volumes     Price     Price     Volumes     Price     2011  
    (Bbls)     ($/Bbl)     (Bbls)     ($/Bbl)     ($/Bbl)     (Bbls)     ($/Bbl)     (In thousands)  
 
April 2011 — December 2011
    500     $ 92.00       180     $ 80.00     $ 94.60       350     $ 90.22     $ (2,130 )
January 2012 — December 2012
    500     $ 92.00       170     $ 81.00     $ 95.85       350     $ 92.40     $ (1,484 )
January 2013 — December 2013
        $       160     $ 82.00     $ 95.60       350     $ 92.71     $ (2,001 )
                                                                 
                                                            $ (5,615 )
                                                                 
 
The following table sets forth the volumes involved in Enduro Sponsor’s three-way oil commodity derivative collars and the weighted-average NYMEX prices per Bbl as of March 31, 2011:
 
                                         
          Average
    Average
    Average
    Fair Value
 
    Daily
    Sub-Floor
    Floor
    Cap
    March 31,
 
Period   Volumes     Price     Price     Price     2011  
    (Bbls)     ($/Bbl)     ($/Bbl)     ($/Bbl)     (In thousands)  
 
April 2011 — December 2011
    500     $ 67.50     $ 90.00     $ 110.00     $ (660 )
January 2012 — December 2012
    500     $ 67.50     $ 90.00     $ 110.00     $ (1,149 )
January 2013 — December 2013
    500     $ 67.50     $ 90.00     $ 110.00     $ (1,030 )
                                         
                                    $ (2,839 )
                                         
 
Interest Rate Risk
 
As of June 30, 2011, Enduro Sponsor had debt outstanding under its revolving credit facility of $231 million. The weighted average annual interest rate under the bank credit facility for the quarter ended June 30, 2011 was 3.3%. If prevailing market interest rates had been 1% higher (or 4.4%), and all other factors affecting Enduro Sponsor’s debt remained the same, interest expense on an annual basis would have increased by $2.4 million.
 
Description of the Enduro Sponsor Operating Agreement
 
The following is a summary of the material provisions of the Amended & Restated Operating Agreement of Enduro Resource Partners LLC (the “Operating Agreement”).
 
Organization and Duration
 
Enduro Sponsor was organized as a Delaware limited liability company on March 3, 2010 and will remain in existence until terminated in accordance with the Operating Agreement. See “— Dissolution.”


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Business
 
The Operating Agreement provides that Enduro Sponsor was organized to (1) engage in the exploration for, and the development and production of, oil and natural gas; the development, ownership and operation of oil and gas infrastructure; and acquiring leases and other real property in that connection and (2) engage in any other business or activity that is necessary, incidental, proper, advisable or convenient in furtherance of or otherwise relating to the purposes set forth in clause (1) above, as determined by the board of managers of Enduro Sponsor in its discretion.
 
Membership Interests; Transferability
 
The equity interests in Enduro Sponsor represent limited liability company interests. The interests cannot be sold, transferred, assigned or otherwise disposed of except in compliance applicable federal and state securities laws.
 
Distributions of Available Cash
 
Enduro Sponsor will distribute to its sole member all cash available for distribution, after giving effect to the obligation of Enduro Sponsor to pay the Net Profits Interest, at such times as may be determined by the sole member in its discretion.
 
Management of Enduro Sponsor
 
The Operating Agreement provides that the board of managers of Enduro Sponsor generally has the complete and exclusive authority to manage, direct and control the business, affairs and properties of Enduro Sponsor.
 
Limited Liability
 
The sole member of Enduro Sponsor is not liable for any obligations or liabilities of Enduro Sponsor unless expressly assumed in writing. Moreover, Enduro Sponsor has agreed to indemnify and hold harmless the sole member and its managers, members, officers and employees (the “indemnitees”) from and against any and all losses, liabilities, expenses and other obligations arising from proceedings in which an indemnitee is involved by reason of the sole member being the member of Enduro Sponsor or the managers, officers or employees of the sole member serving in such capacity, as long as (1) the indemnitee acted in good faith, (2) there has not been a final, non-appealable judgment by a court of competent jurisdiction determining that the indemnitee engaged in fraud, intentional misconduct, knowing and willful breach of its obligations under the Operating Agreement or bad faith or (3) in the case of a criminal matter, the indemnitee had reasonable cause to believe that its conduct was lawful. Any indemnification shall be satisfied solely out of property of Enduro Sponsor, and the sole member and its members are not subject to personal liability. The right to indemnification shall include the right to have Enduro Sponsor pay, in advance of the final disposition of the proceeding, the expenses incurred by the indemnitee who is defending a proceeding, as long as the indemnitee undertakes to repay those advances if it is determined or adjudicated to be ineligible for indemnification.
 
Amendment of the Operating Agreement
 
The Operating Agreement may be amended only by an instrument in writing duly approved by the sole member.
 
Dissolution
 
Enduro Sponsor will continue as a limited liability company until its existence is terminated in accordance with the Operating Agreement. Enduro Sponsor will dissolve upon (1) the approval of the sole member to dissolve Enduro Sponsor, as long as the approval and dissolution would not constitute an event of default under the terms of any agreement of Enduro Sponsor or (2) the occurrence of an


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event that would cause the dissolution of Enduro Sponsor under the Delaware Limited Liability Company Act.
 
Liquidation and Termination
 
Upon dissolution of Enduro Sponsor, a liquidator or liquidating committee approved by the general partner, which may include the sole member or any of its officers, will wind up the affairs and make a final distribution. The liquidator will continue to operate the properties of Enduro Sponsor with all of the power and authority of the sole member necessary or appropriate to liquidate the assets of Enduro Sponsor and apply the proceeds of the liquidation as described in the Operating Agreement. Upon written request of the sole member, the liquidator shall sell Enduro Sponsor’s leases and other properties and assets that otherwise would be distributable to the sole member at the best cash price available and distribute that cash (after deducting all expenses reasonably relating to such sale) to the sole member.


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ENDURO RESOURCE PARTNERS LLC PREDECESSOR:
       
    ENDURO F-2  
    ENDURO F-3  
    ENDURO F-4  
    ENDURO F-5  
    ENDURO F-6  
    ENDURO F-7  
ENDURO RESOURCE PARTNERS LLC:
       
    ENDURO F-19  
    ENDURO F-20  
    ENDURO F-21  
    ENDURO F-22  
    ENDURO F-23  
    ENDURO F-32  
    ENDURO F-33  
    ENDURO F-34  
    ENDURO F-35  
    ENDURO F-36  
    ENDURO F-37  
UNAUDITED PRO FORMA FINANCIAL STATEMENTS:
       
    ENDURO F-52  
    ENDURO F-53  
    ENDURO F-54  
    ENDURO F-55  
    ENDURO F-56  


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Report of Independent Registered Public Accounting Firm
 
The Board of Managers and Members
Enduro Resource Partners LLC
 
We have audited the accompanying carve out balance sheets of Enduro Resource Partners LLC Predecessor (the Company) as of November 30, 2010 and December 31, 2009, and the related carve out statements of operations, owner’s net equity, and cash flows for the years ended December 31, 2008 and 2009, the periods from January 1, 2010 to March 8, 2010 and March 9, 2010 to November 30, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Enduro Resource Partners LLC Predecessor at November 30, 2010 and December 31, 2009, and the results of its operations and its cash flows for the years ended December 31, 2008 and 2009, and for the periods from January 1, 2010 to March 8, 2010 and March 9, 2010 to November 30, 2010, in conformity with U.S. generally accepted accounting principles.
 
As discussed in Note 2 to the financial statements, the Company has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements effective December 31, 2009.
 
/s/  Ernst & Young LLP
 
Fort Worth, Texas
May 12, 2011


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ENDURO RESOURCE PARTNERS LLC PREDECESSOR
 
 
                   
    Predecessor-
      Predecessor-
 
    DNR       EAC  
    November 30,
      December 31,
 
    2010       2009  
(In thousands)              
ASSETS
Current assets:
                 
Accounts receivable
  $ 8,287       $ 11,771  
Prepaid drilling costs
    1,345         3,778  
                   
Total current assets
    9,632         15,549  
                   
Oil and natural gas properties — successful efforts method:
                 
Proved properties
    220,237         368,461  
Unproved properties
    199,130         20,792  
Accumulated depletion, depreciation, and amortization
    (31,707 )       (103,722 )
                   
Total oil and natural gas properties, net
    387,660         285,531  
                   
Other property and equipment, net
    22         47  
                   
Total assets
  $ 397,314       $ 301,127  
                   
 
LIABILITIES AND OWNER’S NET EQUITY
Current liabilities:
                 
Accrued lease operating expense
  $ 1,260       $ 1,205  
Production, ad valorem, and severance taxes payable
    929         739  
Accrued development capital
    19,253         15,684  
Other
    554         656  
                   
Total current liabilities
    21,996         18,284  
                   
Asset retirement obligations
    587         1,404  
                   
Total liabilities
    22,583         19,688  
                   
Commitments and contingencies
                 
Owner’s net equity
    374,731         281,439  
                   
Total liabilities and owners’ net equity
  $ 397,314       $ 301,127  
                   
 
The accompanying notes are an integral part of these carve out financial statements.


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ENDURO RESOURCE PARTNERS LLC PREDECESSOR
 
 
                                   
    Predecessor-
         
    DNR       Predecessor-EAC  
    March 9, 2010
      January 1,
             
    Through
      2010 Through
    Year Ended
    Year Ended
 
    November 30,
      March 8,
    December 31,
    December 31,
 
    2010       2010     2009     2008  
(In thousands)  
Revenues:
                                 
Oil
  $ 1,036       $ 331     $ 1,909     $ 3,295  
Natural gas
    35,503         10,756       31,998       59,075  
Marketing
    3,671         1,077              
                                   
Total revenues
    40,210         12,164       33,907       62,370  
                                   
Expenses:
                                 
Lease operating
    5,285         1,142       7,608       6,343  
Production, ad valorem, and severance taxes
    2,003         548       2,565       2,442  
Gathering and transportation
    2,755         429       2,138       2,577  
Depletion, depreciation, and amortization
    21,754         7,949       33,665       26,716  
Exploration expense
    9,957         231       8,688       723  
Marketing
    3,588         1,060              
General and administrative
    1,254         2,481       5,045       4,001  
Merger-related transaction costs
    6,922         16,136              
Other operating
    24         9       51       28  
                                   
Total expenses
    53,542         29,985       59,760       42,830  
                                   
Operating income (loss)
    (13,332 )       (17,821 )     (25,853 )     19,540  
                                   
Interest expense
    (6,183 )                    
                                   
Net income (loss)
  $ (19,515 )     $ (17,821 )   $ (25,853 )   $ 19,540  
                                   
 
The accompanying notes are an integral part of these carve out financial statements.


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ENDURO RESOURCE PARTNERS LLC PREDECESSOR
 
 
         
    Owner’s Net Equity  
(In thousands)      
 
Predecessor — EAC
       
Balance at January 1, 2008
  $ 105,278  
Net income
    19,540  
Net contributions from owner
    109,615  
         
Balance at December 31, 2008
    234,433  
Net loss
    (25,853 )
Net contributions from owner
    72,859  
         
Balance at December 31, 2009
    281,439  
Net loss
    (17,821 )
Net contributions from owner
    26,455  
         
Balance at March 8, 2010
  $ 290,073  
         
 
Predecessor — DNR
       
Balance at March 9, 2010
  $  
Net loss
    (19,515 )
Net contributions from owner
    394,246  
         
Balance at November 30, 2010
  $ 374,731  
         
 
The accompanying notes are an integral part of these carve out financial statements.


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ENDURO RESOURCE PARTNERS LLC PREDECESSOR
 
 
                                   
    Predecessor -
         
    DNR       Predecessor - EAC  
    March 9, 2010
      January 1,
    Year
    Year
 
    Through
      2010 Through
    Ended
    Ended
 
    November 30,
      March 8,
    December 31,
    December 31,
 
    2010       2010     2009     2008  
(In thousands)                          
Cash flows from operating activities:
                                 
Net income (loss)
  $ (19,515 )     $ (17,821 )   $ (25,853 )   $ 19,540  
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
                                 
Depletion, depreciation, and amortization
    21,754         7,949       33,665       26,716  
Other non-cash items
    9,981         240       8,739       751  
Changes in operating assets and liabilities:
                                 
Accounts receivable
    5,415         (1,931 )     1,897       (5,699 )
Prepaid drilling costs
    4,658         (2,225 )     3,084       (6,862 )
Accrued expenses
    1,403         (1,259 )     1,043       582  
                                   
Net cash provided by (used in) operating activities
    23,696         (15,047 )     22,575       35,028  
                                   
Cash flows from investing activities:
                                 
Development of oil and natural gas properties
    (57,060 )       (11,408 )     (93,620 )     (73,616 )
Acquisition of oil and natural gas properties
    (360,882 )             (1,814 )     (71,027 )
                                   
Net cash used in investing activities
    (417,942 )       (11,408 )     (95,434 )     (144,643 )
                                   
Cash flows from financing activities:
                                 
Net contributions from owner
    394,246         26,455       72,859       109,615  
                                   
Net cash provided by financing activities
    394,246         26,455       72,859       109,615  
                                   
Net increase in cash and cash equivalents
                         
Cash and cash equivalents, beginning of period
                         
                                   
Cash and cash equivalents, end of period
  $       $     $     $ —   
                                   
 
The accompanying notes are an integral part of these carve out financial statements.


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ENDURO RESOURCE PARTNERS LLC PREDECESSOR
 
 
1.   Organization and Nature of Operations
 
Enduro Resource Partners LLC (together with its subsidiaries, “Enduro” or the “Company”), a Delaware limited liability company formed on March 3, 2010 (“Inception”), is engaged in the acquisition, exploration, development, and production of oil and natural gas from properties located in Texas and Louisiana.
 
On December 1, 2010, Enduro completed the acquisition of oil and natural gas properties in East Texas and North Louisiana from Denbury Resources, Inc. (“Denbury” or “DNR”). These properties (the “Predecessor Properties”) were acquired by Denbury on March 9, 2010 in connection with Denbury’s acquisition of Encore Acquisition Company (“Encore” or “EAC”), under which Encore was merged with and into Denbury (the “Merger”).
 
2.   Summary of Significant Accounting Policies
 
Basis of Presentation
 
The accompanying carve out financial statements and related notes thereto represent the carve out financial position, results of operations, cash flows, and changes in owner’s net equity of the Predecessor Properties. As noted above, the Predecessor Properties were acquired by Denbury in March 2010 in connection with the Merger. Because the Merger was accounted for as the acquisition of a business, whereby the purchase price was allocated to identifiable assets and liabilities recorded at fair value, the accompanying carve out financial statements are presented on a different basis for the periods prior to and subsequent to the Merger and are not comparable. Historical financial information of the Predecessor Properties prior to the Merger is referred to as “Predecessor-EAC” and subsequent to the Merger is referred to as “Predecessor-DNR.”
 
The accompanying carve out financial statements have been prepared in accordance with Regulation S-X, Article 3 “General instructions as to financial statements” and Staff Accounting Bulletin (“SAB”) Topic 1-B “Allocations of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity.” Certain expenses incurred by Encore and Denbury are only indirectly attributable to the ownership of the Predecessor Properties as both companies owned interests in numerous other oil and natural gas properties. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to Enduro Resource Partners LLC Predecessor, so that the accompanying carve out financial statements reflect substantially all the costs of doing business. The allocations and related estimates and assumptions are described more fully below.
 
Allocation of Costs
 
The accompanying carve out financial statements have been prepared in accordance with SAB Topic 1-B. These rules require allocations of costs for salaries and benefits, depreciation, rent, accounting and legal services, and other general and administrative expenses. General and administrative expenses prior to March 9, 2010 were allocated to Enduro Resource Partners LLC Predecessor based on the Predecessor Properties’ share of EAC’s total production. In management’s estimation, the allocation methodologies used are reasonable and result in an allocation of the cost of doing business borne by EAC on behalf of Enduro Resource Partners LLC Predecessor; however, these allocations may not be indicative of the cost of future operations or the amount of future allocations. General and administrative expenses subsequent to March 9, 2010 were allocated to Enduro Resource Partners LLC Predecessor based on the Predecessor Properties’ share of DNR’s wholly owned subsidiary, Encore Operating, L.P.’s, total production and an allocation of specifically identifiable costs recognized by Denbury in relation to the Merger. General and administrative expenses for the period


ENDURO F-7


Table of Contents

ENDURO RESOURCE PARTNERS LLC PREDECESSOR
 
NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)
 
from January 1 through March 8, 2010 included allocated legal fees and other transaction costs related to EAC’s preparation for the Merger, which were allocated based on the Predecessor Properties’ share of Encore Operating, L.P.’s volumes.
 
Use of Estimates
 
The preparation of financial statements in conformity with generally accepted accounting principles in the United States (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from those estimates.
 
Significant estimates made in preparing these consolidated financial statements include, among other things, the estimated quantities of proved oil and natural gas reserves used to calculate depletion of oil and natural gas properties; the estimated present value of future net cash flows used in evaluations of impairment and purchase price allocations; accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Changes in the assumptions utilized could have a significant impact on reported results in future periods.
 
Cash and Cash Equivalents
 
Encore and Denbury provided cash as needed to support the operations of the Predecessor Properties and collected cash from sales of production. Consequently, the accompanying Carve Out Balance Sheets of Enduro Resource Partners LLC Predecessor do not include any cash balances. Cash received or paid by EAC and DNR on behalf of the Enduro Resource Partners LLC Predecessor is reflected as net contributions from owner on the accompanying Carve Out Statements of Owner’s Net Equity.
 
Accounts Receivable
 
Enduro Resource Partners LLC Predecessor’s accounts receivable is comprised of invoiced and accrued amounts from oil and natural gas sales. Outstanding accounts receivable balances are reviewed based on the specific facts and circumstances of each outstanding amount and general economic conditions. Neither EAC or DNR had any allowance for doubtful accounts specifically identified for the Predecessor Properties.
 
Oil and Natural Gas Properties
 
Encore followed the successful efforts method of accounting for its oil and natural gas properties while Denbury follows the full cost method of accounting. However, for the period of time Denbury held the Predecessor Properties, transactions continued to be recorded individually by property, and were maintained for internal purposes in a manner similar to the successful efforts method of accounting. As the Predecessor Properties were held by Denbury for a brief period of time, and as Enduro also follows the successful efforts of accounting, for comparability purposes, Enduro converted the financial results for the Predecessor Properties during the period of time they were owned by Denbury to reflect financial results under the successful efforts method of accounting. Enduro Management believes this presentation is more meaningful to the financial statement users. Under this method, all costs associated with productive and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are


ENDURO F-8


Table of Contents

ENDURO RESOURCE PARTNERS LLC PREDECESSOR
 
NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)
 
expensed. Net capitalized costs of unproven property and exploration well costs are reclassified as proved property and well costs when related proved reserves are found.
 
Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive. If an exploration well is unsuccessful in finding proved reserves, the capitalized well costs are charged to exploration expense. Enduro Resource Partners LLC Predecessor did not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheet following the completion of drilling unless both of the following conditions were met:
 
(i) The well found a sufficient quantity of reserves to justify its completion as a producing well, and
 
(ii) The Enduro Resource Partners LLC Predecessor was making sufficient progress in assessing the reserves and the economic and operating viability of the project.
 
Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable.
 
Costs of significant nonproducing properties and exploratory wells in progress of being drilled are excluded from depletion until such time as the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.
 
Long-lived assets to be held and used, including proved oil and natural gas properties, are reviewed whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. If an impairment loss is indicated by the carrying amount of the assets exceeding the sum of the undiscounted expected future net cash flows, then an impairment loss is recognized for the amount by which the carrying amount of the asset exceeds its estimated fair value. Estimates of the sum of expected future cash flows require management to estimate future recoverable proved and risk-adjusted probable and possible reserves, forecasts of future commodity prices, production and capital costs, and discount rates. Uncertainties about these future cash flow variables cause impairment estimates to be inherently imprecise.
 
Unproved oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. The impairment assessment is affected by the results of exploration activities, commodity price outlooks, planned future sales, or expiration of all or a portion of such projects. If the quantity of potential reserves determined by such evaluation is not sufficient to fully recover the cost invested in each project, Enduro Resource Partners LLC Predecessor will recognize an impairment loss at the time such determination is made.
 
Other Property and Equipment
 
Other property and equipment is carried at cost and consists of transportation equipment used in field operations. Depreciation is expensed on a straight-line basis over estimated useful lives, which range from 5 to 6 years. During 2009, approximately $11,000 was recognized in depreciation expense; for the period from January 1, 2010 through March 8, 2010, approximately $2,000 was recognized in depreciation expense; and for the period from March 8, 2010 through November 30, 2010, approximately $4,000 was recorded in depreciation expense. Depreciation expense was not material in 2008.


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ENDURO RESOURCE PARTNERS LLC PREDECESSOR
 
NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)
 
Asset Retirement Obligations
 
Liability for the fair value of an asset retirement obligation is recorded in the period in which it is incurred. For oil and natural gas properties, this is the period in which the property is acquired or a new well is drilled. Asset retirement obligations are capitalized as part of the carrying values of the long-lived assets.
 
Asset retirement obligations are recorded at the present value of expected future net cash flows and are discounted using Encore’s and Denbury’s credit adjusted risk free rate, respectively, and then accreted until settled or sold, at which time the liability is reversed. Estimates are based on average plugging and abandonment well costs and estimated remaining field life based on reserve estimates.
 
Owner’s Net Equity
 
Since Enduro Resource Partners LLC Predecessor was not a separate legal entity during the period covered by these carve out financial statements, none of EAC’s debt is directly attributable to its ownership of the Predecessor Properties, and no formal intercompany financing arrangement existed related to the Predecessor Properties. Therefore, the change in net assets in each year that is not attributable to current period earnings, is reflected as an increase or decrease to owner’s net equity for that year. Additionally, as debt cannot be specifically ascribed to the purchase of the Predecessor Properties for the period prior to March 9, 2010, the accompanying Carve Out Statements of Operations do not include any allocation of interest expense incurred by Encore to Enduro Resource Partners LLC Predecessor. However, as Denbury specifically incurred debt related to the Merger, Denbury’s debt incurred in the first quarter of 2010 is directly attributable in part to its ownership of the Predecessor Properties, and interest expense was allocated to the Predecessor Properties through owner’s net equity.
 
Revenue Recognition
 
Sales of oil and natural gas are recognized when such products have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Enduro Resource Partners LLC Predecessor sells oil and natural gas on a monthly basis. Virtually all of the contract pricing provisions are tied to a market index. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Accounts receivable” in the accompanying Carve Out Balance Sheets.
 
Enduro Resource Partners LLC Predecessor uses the sales method of accounting for oil and natural gas revenues, recognizing revenues based on the oil and natural gas delivered rather than its working interest share of oil and natural gas produced.
 
Enduro Resource Partners LLC Predecessor had no material imbalances as of November 30, 2010.
 
Marketing revenues derived from sales of oil or natural gas purchased from third parties are recognized when persuasive evidence of a sales arrangement exists, delivery has occurred, the sales price is fixed or determinable, and collectibility is reasonably assured. As the Company takes title to the oil and natural gas and has risks and rewards of ownership, these transactions are presented gross in marketing revenue and marketing expense in the accompanying Consolidated Statement of Operations, unless they meet the criteria for netting as outlined in the Accounting for Purchases and Sales of


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Table of Contents

ENDURO RESOURCE PARTNERS LLC PREDECESSOR
 
NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)
 
Inventory with the Same Counterparty topic of the Financial Accounting Standards Board Codification (“ASC”).
 
Income Taxes
 
During the periods presented, the operations of Enduro Energy Partners LLC Predecessor were included in various partnership entities, which were classified as a partnership for federal income tax purposes; thus, earnings were not subject to federal income tax. Similarly, most states treat entities classified as partnerships for federal income tax purposes as partnerships for state purposes. As such, income tax liabilities are passed through to the partners.
 
Texas imposes an entity-level tax on all forms of business regardless of federal entity classification. Enduro Energy Partners LLC Predecessor’s Texas tax liability was not material during the periods presented, accordingly, no income tax expense has been recorded in the carve out financial statements.
 
Earnings per Share
 
Prior to the Merger, the Predecessor Properties were wholly owned by EAC while subsequent to the Merger the Predecessor Properties were wholly owned by DNR. The Predecessor Properties were not a separate legal entity and no shares or units existed. Accordingly, earnings per share has not been presented.
 
Segments
 
The Company has significant operations in only one industry segment and one geographic operating segment, that being the oil and natural gas exploration and production industry in the United States of America.
 
Recently Issued Accounting Pronouncements
 
The following discussion provides information about new accounting pronouncements:
 
In December 2008, the SEC released the final rule on “Modernization of Oil and Gas Reporting” (the “Reserve Ruling”). The Reserve Ruling revises oil and gas reporting disclosures. The Reserve Ruling also permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The Reserve Ruling will also allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor, (ii) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit and (iii) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price. The Reserve Ruling became effective for fiscal years ending on or after December 31, 2009. During December 2009, the FASB issued Accounting Standards Update No. 2010-03, “Extractive Activities — Oil and Gas (Topic 932),” (“ASU 2010-03”) to conform generally accepted accounting principles to the Reserve Ruling. The Company adopted the provisions of the Reserve Ruling and the provisions of ASU 2010-03 on December 31, 2009.
 
In September 2006, the FASB issued guidance to define fair value, establish a framework for measuring fair value, and to enhance disclosures about fair value measures required under other accounting pronouncements. In January 2010, the FASB issued guidance to (i) require separate disclosure of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers, (ii) require separate disclosure of purchases, sales, issuances, and settlements


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Table of Contents

ENDURO RESOURCE PARTNERS LLC PREDECESSOR
 
NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)
 
in the reconciliation for fair value measurements using significant unobservable inputs (Level 3), (iii) clarify the level of disaggregation for fair value measurements of assets and liabilities, and (iv) clarify disclosures about inputs and valuation techniques used to measure fair values for both recurring and nonrecurring fair value measurements. The implementation did not have a material effect on the financial condition or results of operations of Enduro Resource Partners LLC Predecessor. See Note 4 for additional information regarding the Predecessor Properties’ fair value measurements.
 
3.   Acquisition
 
On March 9, 2010, Denbury merged with Encore with Denbury being the surviving entity. The Predecessor Properties were, therefore, owned by EAC prior to March 8, 2010 and DNR subsequent to the Merger. The transaction was accounted for as the acquisition of a business, thus identifiable assets and liabilities were recorded at fair value. Fair values of the Predecessor Properties were carved out of DNR’s fair value allocation which was based on a discounted cash flows model.
 
Since Denbury funded the Merger partially through borrowings, $149.1 million of debt was attributed to Enduro Resource Partners LLC Predecessor for the purpose of allocating interest expense to the carve out financial statements based on the relative fair value of the Predecessor Properties to Denbury’s allocated fair value of Encore. The carve out purchase price allocation related to the Predecessor Properties are as follows (in thousands):
 
         
Proved oil and natural gas properties
  $ 164,154  
Unproved properties
    199,130  
Other equipment
    26  
Accounts receivable
    13,702  
Prepaid drilling costs
    6,003  
         
Total assets acquired
    383,015  
         
Accrued development costs
    (20,235 )
Asset retirement obligations
    (558 )
Operating payables
    (1,340 )
         
Total liabilities assumed
    (22,133 )
         
Fair value of net assets acquired
  $ 360,882  
         
 
The operations of the properties acquired have been included in the Enduro Resource Partners LLC Predecessor’s results of operations since the Merger date.
 
4.   Disclosures About Fair Value Measurements
 
Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:
 
  •      Level 1 — Unadjusted quoted prices are available for identical assets or liabilities in active markets.
 
  •      Level 2 — Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than


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ENDURO RESOURCE PARTNERS LLC PREDECESSOR
 
NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)
 
  quoted prices that are observable for the asset or liability (e.g., interest rates); and inputs derived principally from or corroborated by observable market data by correlation or other means.
 
  •      Level 3 — Unobservable inputs for the asset or liability.
 
The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level of input that is significant to the measurement in its entirety.
 
Enduro Resource Partners LLC Predecessor has financial instruments consisting primarily of accounts receivable, other current assets, and accounts payable that approximate fair value due to the short maturity of these instruments.
 
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
 
Allocated properties bought in connection with Denbury’s purchase of Encore were recorded at fair value, which was determined using a risk-adjusted discounted cash flow. The fair value of oil and natural gas properties is based on significant inputs not observable in the market. Key assumptions include (i) NYMEX oil and natural gas futures prices, which are observable, (ii) projections of the estimated quantities of oil and natural gas reserves, including those classified as proved, probable, and possible, (iii) projections of future rates of production, (iv) timing and amount of future development and operating costs, (v) projected recovery factors, and (vi) risk-adjusted discount rates.
 
Asset retirement obligations are recorded at fair value. Unobservable inputs are used in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered Level 3 measurements in the fair value hierarchy.
 
Enduro Resource Partners LLC Predecessor’s review of oil and natural gas impairment involves estimation of fair values. Primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and natural gas properties are based on (i) proved reserves and risk-adjusted probable and possible reserves, (ii) commodity price outlook, which would be used by purchasers, including assumptions as to inflation of costs and expenses, and (iii) the estimated discount rate that would be used by purchasers to assess the fair value of the assets. There were no impairments recognized through November 30, 2010.
 
Concentrations of Credit Risk
 
The following purchasers accounted for 10% or greater of the sales of production for the period indicated:
 
                                   
    Predecessor -
     
    DNR     Predecessor - EAC
    March 9, 2010
        Year
   
    Through
    January 1,
  Ended
  Year Ended
    November 30,
    2010 Through
  December 31,
  December 31,
    2010     March 8, 2010   2009   2008
Camterra Resources, Inc. 
    28 %       33 %     31 %     34 %
Chesapeake Operating, Inc. 
    17 %       *       *       *  
Petrohawk Energy Corporation
    11 %       12 %     24 %     26 %
Spark Energy
    20 %       23 %     *       *  
 
 
* Less than 10% for the period indicated.


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Table of Contents

ENDURO RESOURCE PARTNERS LLC PREDECESSOR
 
NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)
 
 
Loss of any of these purchasers would not have an adverse effect on the ability of Enduro Resource Partners LLC Predecessor to sell its oil and natural gas production. However, it is possible that the loss of any one of these customers could have an adverse effect on the price received for oil and natural gas sales.
 
5.   Asset Retirement Obligations
 
Asset retirement obligations presented in the accompanying Carve Out Balance Sheets relate to the future plugging and abandonment of wells and related facilities. The following table summarizes asset retirement obligations (in thousands):
 
                           
    Predecessor- DNR       Predecessor - EAC  
            January 1,
    Year
 
    March 9, 2010
      2010 Through
    Ended
 
    Through
      March 8,
    December 31,
 
    November 30, 2010       2010     2009  
Beginning asset retirement obligations
  $       $ 1,404     $ 1,322  
Liabilities assumed at acquisition
    558                
Wells drilled
    5               268  
Change in estimate
            (1 )     (237 )
Accretion of discount
    24         9       51  
                           
Ending asset retirement obligations
  $ 587       $ 1,412     $ 1,404  
                           
 
Above liabilities are recorded in “Asset retirement obligations” on the accompanying Carve Out Balance Sheets. Accretion is included in “Other operating” in the accompanying Carve Out Statement of Operations.
 
6.   Commitments and Contingencies
 
General
 
From time to time, the Enduro Resource Partners LLC Predecessor is a party to litigation or other legal proceedings that is considered to be a part of the ordinary course of business. Enduro Resource Partners LLC Predecessor is not currently involved in any legal proceedings that could be allocable and related to the Predecessor Properties. Liabilities are accrued when it is probable that future costs will be incurred and such costs can be reasonably estimated.
 
Lease Agreements
 
Enduro Resource Partners LLC Predecessor leases compressors on a month-to-month basis which are used in the field operations of the Predecessor Properties. There are no long-term lease commitments directly attributable to the Predecessor Properties that are non-cancellable.
 
Firm Transportation Agreement
 
Encore entered into a 10-year firm transportation contract in January 2010 that relates to the Predecessor Properties. The contract has a non-cancellable commitment to transport 22,500 million British thermal units (“MMBtu”) per day of natural gas for a minimum transportation fee of $0.30 per MMBtu. During 2010, no oil and natural gas volumes were transported under this agreement; however, the minimum transportation fee for the daily volumes totaled $2.3 million from January 1 to November 30, 2010. There were no dedicated reserves to fulfill this commitment.


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ENDURO RESOURCE PARTNERS LLC PREDECESSOR
 
NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)
 
The following table summarizes the remaining non-cancelable future payments under this firm transportation contract as of November 30, 2010 (in thousands):
 
         
2010
  $ 209  
2011
    2,464  
2012
    2,470  
2013
    2,464  
2014
    2,464  
2015
    2,464  
Thereafter
    10,059  
         
    $ 22,594  
         
 
7.   Subsequent Events
 
As discussed above, the Predecessor Properties were owned by Encore prior to March 9, 2010 and by Denbury subsequent to the Merger. On December 1, 2010 Enduro Resource Partners LLC purchased these assets from Denbury for $213.8 million after preliminary closing adjustments.
 
8.   Supplemental Oil and Natural Gas Disclosures (Unaudited)
 
Costs Incurred for Oil and Natural Gas Producing Activities
 
                                   
    Predecessor-
         
    DNR       Predecessor-EAC  
    March 9
      January 1, 2010
    Year
    Year
 
    Through
      Through
    Ended
    Ended
 
    November 30,
      March 8,
    December 31,
    December 31,
 
    2010       2010     2009     2008  
(In thousands)                          
Proved acquisitions
  $ 164,154       $     $     $ 56,186  
Unproved acquisitions
    199,130               1,814       14,841  
                                   
Total acquisitions
    363,284               1,814       71,027  
Exploratory costs
    9,945         11,534       59,092       29,057  
Development costs
    46,138         4,424       30,742       59,546  
                                   
Total costs incurred
  $ 419,367       $ 15,958     $ 91,648     $ 159,630  
                                   
 
The following unaudited supplemental oil and natural gas disclosures were derived from reserve reports which were prepared by reserve engineers at Enduro Resource Partners LLC, Denbury and Encore and are presented in accordance with the Financial Accounting Standards Board ASC Topic 932, Extractive Activities — Oil and Gas (“ASC 932”). The unaudited supplemental information reflects the revised oil and natural gas reserve estimation and disclosure requirements of the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC in 2008 and were effective December 31, 2009. The following unaudited supplemental information for 2010 and 2009 has been presented in accordance with the revised reserve estimation and disclosure rules, which were not applied retrospectively. Accordingly, the information for 2008 is presented in accordance with the oil and gas disclosure requirements effective during that period.
 
Oil and Natural Gas Reserve Quantities
 
Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of proved reserves and in the projection of future rates of production and the timing of


ENDURO F-15


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ENDURO RESOURCE PARTNERS LLC PREDECESSOR
 
NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)
 
development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing, and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The process of estimating quantities of oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reserve. Consequently, material revisions to existing reserve estimates may occur from time to time.
 
The following table presents the estimated remaining net proved and proved developed oil and natural gas reserves of the Predecessor Properties, for the periods indicated. Oil volumes are expressed in thousands of barrels (“MBbls”), gas volumes are expressed in thousands of Mcf (“MMcf”) and total volumes are expressed in thousands of barrels of oil equivalent (“MBOE”).
 
                           
    Predecessor-
     
    DNR     Predecessor-EAC
    November 30,
    December 31,
  December 31,
    2010     2009   2008
Proved reserves
                         
Oil (MBbl)
    112         114       151  
Natural gas (MMcf)
    107,686         108,906       61,239  
Combined (MBOE)
    18,059         18,265       10,357  
Proved developed reserves
                         
Oil (MBbl)
    67         69       106  
Natural gas (MMcf)
    57,673         53,667       46,378  
Combined (MBOE)
    9,679         9,014       7,836  
 
The following table provides a rollforward of total proved reserves for the year ended December 31, 2009 and 2008 as well as periods ended March 8, 2010 and November 30, 2010.
 
                         
    Oil
    Natural Gas
    Combined
 
    (MBbls)     (MMcf)     (MBOE)  
 
Predecessor — EAC:
                       
Balance as of January 1, 2008
    114       39,495       6,696  
Revisions of estimates
    73       28,690       4,855  
Production
    (36 )     (6,946 )     (1,194 )
                         
Balance as of December 31, 2008
    151       61,239       10,357  
Revisions of estimates
    (2 )     56,236       9,371  
Production
    (35 )     (8,569 )     (1,463 )
                         
Balance as of December 31, 2009
    114       108,906       18,265  
Production
    (5 )     (1,941 )     (329 )
                         
Balance as of March 8, 2010
    109       106,965       17,936  
 
Predecessor — DNR:
                       
Balance as of March 9, 2010
                 
Acquisitions
    126       116,630       19,564  
Production
    (14 )     (8,944 )     (1,505 )
                         
Balance as of November 30, 2010
    112       107,686       18,059  


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ENDURO RESOURCE PARTNERS LLC PREDECESSOR
 
NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)
 
Standardized Measure of Discounted Future Net Cash Flows
 
Estimated discounted future net cash flows and changes therein were determined for the Predecessor Properties in accordance with ASC 932. Future cash inflows for 2009 were computed by applying the average prices of oil and natural gas during the 12-month period to the period-end quantities of those proved reserves (with consideration of price changes only to the extent provided by contractual arrangements). The average prices were determined using the arithmetic average of the prices in effect on the first day of the month for each month within the period which were $61.18 per Bbl for oil and $3.83 per Mcf for natural gas. This same 12-month average price was also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. Future cash inflows for 2008 were computed by using the year-end oil and natural gas prices in accordance with the disclosure requirements effective during that period. Prices used for 2008 were $44.60 per Bbl for oil and $5.62 per Mcf for natural gas. For 2010 $78.73 per Bbl and $4.38 per Mcf were used.
 
Future development and production costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves based on period-end costs assuming continuation of existing economic conditions. An annual discount rate of 10% was used to reflect the timing of the future net cash flows.
 
Discounted future cash flow estimates like those shown below are not intended to present, nor should they be interpreted to present, the fair value of the Predecessor Properties’ oil and natural gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future commodity prices, interest rates, changes in development and production costs, and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.
 
The following tables provide the standardized measure of discounted future cash flows as of as of the dates indicated, as well as a rollforward in total for the period (in thousands):
 
                                   
    Predecessor-
         
    DNR       Predecessor - EAC  
    November
      March 8,
    December 31,
    December 31,
 
    30, 2010       2010     2009     2008  
Oil and natural gas producing activities:
                                 
Future cash inflows
  $ 433,755       $ 377,488     $ 388,575     $ 333,413  
Future production costs
    (141,262 )       (119,095 )     (121,214 )     (102,007 )
Future development costs
    (33,462 )       (87,435 )     (103,393 )     (39,563 )
                                   
Undiscounted future net cash flows
    259,031         170,958       163,968       191,843  
10% annual discount factor
    (87,408 )       (101,132 )     (102,162 )     (89,016 )
                                   
Standardized measure of discounted future cash flows
  $ 171,623       $ 69,826     $ 61,806     $ 102,827  
                                   


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Table of Contents

ENDURO RESOURCE PARTNERS LLC PREDECESSOR
 
NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)
 
The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves (in thousands):
 
                                   
    Predecessor-
         
    DNR       Predecessor-EAC  
    March 8,
      January 1,
             
    2010
      2010
    Year
    Year
 
    Through
      Through
    Ended
    Ended
 
    November 30,
      March 8,
    December
    December
 
    2010       2010     31, 2009     31, 2008  
Oil and natural gas sales, net of production costs
  $ (26,496 )     $ (8,968 )   $ (21,596 )   $ (51,008 )
Net change in sales price and production costs
                  (46,255 )     (18,432 )
Revisions of quantity estimates
                  44,159       59,189  
Previously estimated development costs incurred
    56,083         15,958       39,563       28,087  
Change in estimated future development costs
                  (63,830 )     (25,759 )
Accretion of discount
    9,909         1,030       10,283       9,947  
Change in timing and other
                  (3,345 )     1,335  
Purchases of minerals-in-place
    132,127                      
                                   
Net change in standardized measure
    171,623         8,020       (41,021 )     3,359  
Standardized measure balance, beginning of period
            61,806       102,827       99,468  
                                   
Standardized measure balance, end of period
  $ 171,623       $ 69,826     $ 61,806     $ 102,827  
                                   


ENDURO F-18


Table of Contents

 
ENDURO RESOURCE PARTNERS LLC
 
CONSOLIDATED BALANCE SHEETS
 
                 
    March 31,
    December 31,
 
    2011     2010  
    (Unaudited)        
    (In thousands, except unit amounts)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 1,956     $ 53,984  
Accounts receivable — trade
    21,841       7,215  
Prepaid expenses
    438       223  
Derivatives
    2,615       3,075  
                 
Total current assets
    26,850       64,497  
                 
Oil and natural gas properties — successful efforts method of accounting:
               
Proved properties
    677,439       209,723  
Unproved properties
    35,046       34,569  
Accumulated depletion, depreciation, and amortization
    (12,759 )     (1,946 )
                 
Total oil and natural gas properties, net
    699,726       242,346  
                 
Other property and equipment, net
    226       184  
Acquisition deposits
          47,500  
Derivatives
    5,726       5,655  
Other
    3,278       1,650  
                 
Total assets
  $ 735,806     $ 361,832  
                 
 
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
               
Accounts payable
  $ 2,629     $ 786  
Accrued liabilities:
               
Lease operating
    3,541       1,667  
Development capital
    8,922       10,565  
Production taxes, transportation, and marketing
    1,367       748  
Derivatives
    4,882       1,044  
Current portion of firm transportation contract liability
    2,471       2,464  
Oil and natural gas revenues payable
    723       1,832  
Other
    5,736       2,576  
                 
Total current liabilities
    30,271       21,682  
                 
Long-term debt
    233,000       52,000  
Derivatives
    6,834       1,990  
Asset retirement obligations, net of current portion
    9,599       1,496  
Firm transportation contract liability, net of current portion
    10,844       10,700  
Other
    115       25  
                 
Total liabilities
    290,663       87,893  
                 
Commitments and contingencies
               
Members’ equity:
               
Class A, 464,860,000 and 282,160,500 units issued and outstanding, respectively
    445,143       273,939  
Class B, 96,500 and 96,000 units issued and outstanding, respectively
           
                 
Total members’ equity
    445,143       273,939  
                 
Total liabilities and members’ equity
  $ 735,806     $ 361,832  
                 
 
The accompanying notes are an integral part of these unaudited consolidated financial statements.


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ENDURO RESOURCE PARTNERS LLC
 
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
 
                 
    Three
    March 3, 2010
 
    Months
    (Inception)
 
    Ended
    Through
 
    March 31, 2011     March 31, 2010  
    (In thousands, except per unit amounts)  
 
Revenues:
               
Oil
  $ 10,236     $      —  
Natural gas
    11,899        
Marketing
    817        
                 
Total revenues
    22,952        
                 
Expenses:
               
Lease operating
    4,007        
Production, ad valorem, and severance taxes
    1,447        
Gathering and transportation
    794        
Depletion, depreciation, and amortization
    10,830        
Marketing
    795        
General and administrative
    3,043       77  
Derivative fair value loss
    11,449        
Other operating
    896        
                 
Total expenses
    33,261       77  
Operating loss
    (10,309 )     (77 )
                 
Interest expense, net
    (1,220 )      
                 
Loss before income taxes
    (11,529 )     (77 )
Deferred income tax benefit
    34        
                 
Net loss
  $ (11,495 )   $ (77 )
                 
Net loss per Class A unit — basic and diluted
  $ (0.03 )   $  
Weighted average units outstanding — Class A:
               
Basic
    367,417        
Diluted
    367,417        
 
The accompanying notes are an integral part of these unaudited consolidated financial statements.


ENDURO F-20


Table of Contents

 
ENDURO RESOURCE PARTNERS LLC
 
UNAUDITED CONSOLIDATED STATEMENT OF CHANGES IN MEMBERS’ EQUITY
 
                         
                Members’
 
    Class A Units     Class B Units     Equity  
    (In thousands, except units)  
 
Balance at December 31, 2010
    282,160,500       96,000     $ 273,939  
Contributions from members
    182,699,500             182,699  
Issuance of Class B units
          500        
Net loss
                    (11,495 )
                         
Balance at March 31, 2011
    464,860,000       96,500     $ 445,143  
                         
 
The accompanying notes are an integral part of these unaudited consolidated financial statements.


ENDURO F-21


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ENDURO RESOURCE PARTNERS LLC
 
 
                 
    Three
    March 3,
 
    Months
    2010
 
    Ended
    (Inception)
 
    March 31,
    Through
 
    2011     March 31, 2010  
    (In thousands)  
 
Cash flows from operating activities:
               
Net loss
  $ (11,495 )   $ (77 )
Adjustments to reconcile net loss to net cash used in operating activities:
               
Depletion, depreciation, and amortization
    10,830        
Unrealized loss on derivatives
    11,821        
Other non-cash items
    853        
Changes in operating assets and liabilities:
               
Accounts receivable
    (12,227 )      
Prepaid expenses
    1,163        
Derivative assets
    (2,750 )      
Accounts payable and other accrued expenses
    (9,794 )     77  
                 
Net cash used in operating activities
    (11,599 )      
                 
Cash flows from investing activities:
               
Development of oil and natural gas properties
    (1,592 )      
Acquisition of oil and natural gas properties
    (400,980 )      
Purchases of other property and equipment
    (59 )      
                 
Net cash used in investing activities
    (402,631 )      
                 
Cash flows from financing activities:
               
Contributions from members
    182,699       100  
Proceeds from long-term debt borrowings
    181,000        
Payment of deferred loan costs
    (1,497 )      
                 
Net cash provided by financing activities
    362,202       100  
                 
Net increase (decrease) in cash and cash equivalents
    (52,028 )     100  
Cash and cash equivalents, beginning of period
    53,984        
                 
Cash and cash equivalents, end of period
  $ 1,956     $ 100  
                 
 
The accompanying notes are an integral part of these unaudited consolidated financial statements.


ENDURO F-22


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
1.   Organization and Nature of Operations
 
Enduro Resource Partners LLC (together with its subsidiaries, “Enduro” or “the Company”), a Delaware limited liability company formed on March 3, 2010 (“Inception”), is engaged in the acquisition, exploration, development, and production of oil and natural gas from properties located in Texas, Louisiana, and New Mexico.
 
Principles of Consolidation
 
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.
 
In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments necessary to present fairly, in all material respects, the Company’s financial position as of March 31, 2011, results of operations and cash flows for the three months ended March 31, 2011 and the Company’s financial position as of December 31, 2010, results of operations and cash flows for the period from March 3, 2010 (“Inception”) through March 31, 2011. All adjustments are of a normal recurring nature. These interim results are not necessarily indicative of results for an entire year.
 
Certain amounts and disclosures have been condensed or omitted from these consolidated financial statements pursuant to the rules and regulations of the SEC. Therefore, these consolidated financial statements should be read in conjunction with the Enduro Resource Partners LLC consolidated financial statements and notes thereto included elsewhere in this prospectus.
 
2.   Acquisitions
 
Denbury Acquisition
 
On December 1, 2010, the Company completed an acquisition of oil and natural gas properties in East Texas and North Louisiana from Denbury Resources, Inc. (the “Denbury Acquisition”). These properties constitute all of the Company’s oil and gas assets as of December 31, 2010. Prior to December 1, 2010 the Company did not have any significant operations.
 
Total consideration paid for the properties at closing was $217.4 million after preliminary closing adjustments. The Company funded the acquisition through member capital contributions and borrowings under its revolving credit facility. The Denbury Acquisition was accounted for as a business and recorded at fair value, which was determined using a risk-adjusted discounted cash flow analysis. The purchase price allocation for the acquisition is preliminary and subject to revision pending finalization of closing adjustments.


ENDURO F-23


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The following table presents a summary of the preliminary fair value of assets acquired and liabilities assumed at the acquisition date (in thousands):
 
         
Oil and natural gas properties
  $ 245,245  
Other equipment
    24  
Accounts receivable
    4,950  
         
Total assets acquired
    250,219  
         
Asset retirement obligations
    (2,542 )
Firm transportation contract liability
    (13,762 )
Operating payables
    (16,543 )
         
Total liabilities assumed
    (32,847 )
         
Fair value of net assets acquired
  $ 217,372  
         
 
The operations of the properties acquired above have been included in the Company’s results of operations since the date of closing. The Company incurred $0.6 million of expenses in connection with the acquisition.
 
Samson Acquisition
 
On January 5, 2011, the Company completed an acquisition of oil and natural gas properties located in the Permian Basin of New Mexico and West Texas from Samson Investment Company (the “Samson Acquisition”).
 
Total consideration paid for the properties at closing was $133.8 million after preliminary closing adjustments. The Company funded the acquisition through member capital contributions and borrowings under its revolving credit facility. The Samson Acquisition was accounted for as a business and recorded at fair value, which was determined using a risk-adjusted discounted cash flow analysis. The purchase price allocation for the acquisition is preliminary and subject to revision pending finalization of closing adjustments.
 
The following table presents a summary of the preliminary fair value of assets acquired and liabilities assumed at the acquisition date (in thousands):
 
         
Oil and natural gas properties
  $ 131,780  
Accounts receivable
    2,780  
         
Total assets acquired
    134,560  
         
Asset retirement obligations
    (722 )
         
Total liabilities assumed
    (722 )
         
Fair value of net assets acquired
  $ 133,838  
         
 
The operations of the properties acquired above have been included in the Company’s results of operations since the date of closing. The Company incurred $0.5 million of expenses in connection with the acquisition, which is recorded in “General and administrative” expense in the accompanying Unaudited Consolidated Statements of Operations.
 
ConocoPhillips Acquisition
 
On February 28, 2011, the Company completed an acquisition of oil and natural gas properties in Texas and New Mexico from ConocoPhilips Company (the “ConocoPhillips Acquisition”).


ENDURO F-24


Table of Contents

ENDURO RESOURCE PARTNERS LLC
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Total consideration paid for the properties at closing was $314.2 million after preliminary closing adjustments. The Company funded the acquisition through member capital contributions and borrowings under its revolving credit facility. The ConocoPhillips Acquisition was accounted for as a business and recorded at fair value, which was determined using a risk-adjusted discounted cash flow analysis. The purchase price allocation for the acquisition is preliminary and subject to revision pending finalization of closing adjustments.
 
The following table presents a summary of the preliminary fair value of assets acquired and liabilities assumed at the acquisition date (in thousands):
 
         
Oil and natural gas properties
  $ 321,520  
Asset retirement obligations
    (7,357 )
         
Fair value of net assets acquired
  $ 314,163  
         
 
The operations of the properties acquired above have been included in the Company’s results of operations since the date of closing. The Company incurred $0.4 million of expenses in connection with the acquisition, which is recorded in “General and administrative” expense in the accompanying Unaudited Consolidated Statements of Operations.
 
Pro Forma Information
 
The following unaudited pro forma combined condensed financial data for the three months ended March 31, 2011 and 2010 assumes the acquisitions occurred on January 1, 2010. The unaudited pro forma combined condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the acquisition taken place as of the dates indicated and is not intended to be a projection of future results.
 
                 
    Three Months Ended
 
    March 31,  
    2011     2010  
    (In thousands, except per unit amounts)  
 
Pro forma total revenues
  $ 33,793     $ 20,127  
                 
Pro forma net income (loss)
  $ (9,559 )   $ 1,441  
                 
Pro forma net income (loss) per unit:
               
Basic
  $ (0.02 )   $  
Diluted
  $ (0.02 )   $  
 
3.   Disclosures About Fair Value Measurements
 
Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:
 
  •  Level 1 — Unadjusted quoted prices are available for identical assets or liabilities in active markets.
 
  •  Level 2 — Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
  quoted prices that are observable for the asset or liability (e.g., interest rates); and inputs derived principally from or corroborated by observable market data by correlation or other means.
 
  •  Level 3 — Unobservable inputs for the asset or liability.
 
The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level of input that is significant to the measurement in its entirety.
 
The Company has classified its derivative contracts into one of the three levels based upon the data relied upon to determine the fair value. The fair values are based upon quotes obtained from counterparties to the derivative contracts. The Company reviews other readily available market prices for its derivative contracts as there is an active market for these contracts; however, the Company does not have access to specific valuation models used by the counterparties. Included in these models are discount factors that the Company must estimate in its calculation. The Company’s swap contracts are classified as Level 2, while its floors and collars are classified as Level 3.
 
The following tables set forth the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2011 (in thousands):
 
                                 
          Fair Value Measurements at Reporting Date Using  
          Quoted Prices
             
          in Active
    Significant
       
    Fair Value
    Markets for
    Other
    Significant
 
    as of
    Identical
    Observable
    Unobservable
 
    March 31,
    Assets
    Inputs
    Inputs
 
    2011     (Level 1)     (Level 2)     (Level 3)  
 
Oil and natural gas derivative contracts — assets
  $ 8,341     $     $ 182     $ 8,159  
Oil and natural gas derivative contracts — liabilities
    11,716             6,327       5,389  
 
The following table presents the changes in fair values of the Company’s financial instruments measured using significant unobservable inputs (Level 3) during the three months ended March 31, 2011 (in thousands):
 
                 
    Derivative Contracts –
 
    Floors and Caps  
    Oil     Natural Gas  
 
Balance at December 31, 2010
  $ 2,997     $ 4,884  
Purchases
          2,750  
Settlements
    47       (295 )
Unrealized gains (losses) included in earnings
    (6,749 )     (864 )
                 
Balance at March 31, 2011
  $ (3,705 )   $ 6,475  
                 


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The following table presents the carrying amounts and fair values of the Company’s financial instruments as of the dates indicated (in thousands):
 
                                 
    December 31, 2010     March 31, 2011  
    Carrying
    Fair
    Carrying
    Fair
 
    Value     Value     Value     Value  
 
Financial assets:
                               
Natural gas commodity contracts — current asset
  $ 1,639     $ 1,639     $ 2,087     $ 2,087  
Oil commodity contracts — current asset
    1,436       1,436       528       528  
Natural gas commodity contracts — long-term asset
    3,386       3,386       4,776       4,776  
Oil commodity contracts — long-term asset
    2,269       2,269       950       950  
Financial liabilities:
                               
Natural gas commodity contracts — current liabilities
    333       333       768       768  
Oil commodity contracts — current liabilities
    711       711       4,114       4,114  
Natural gas commodity contracts — long-term liabilities
    1,120       1,120       1,016       1,016  
Oil commodity contracts — long-term liabilities
    870       870       5,818       5,818  
Long-term debt
    52,000       52,000       233,000       233,000  
 
The Company has other financial instruments consisting primarily of cash and cash equivalents, accounts receivable, other current assets, and accounts payable that approximate fair value due to the short maturity of these instruments.
 
Long-Term Debt
 
The carrying amount of bank debt approximates fair value because these instruments bear interest at variable market rates, which approximates the current market rates as of March 31, 2011 and as of December 31, 2010.
 
4.   Derivative Financial Instruments
 
The Company uses derivative financial instruments to reduce exposure to commodity price fluctuations. Derivative instruments are recorded at fair value and included on the Consolidated Balance Sheets as assets or liabilities. The Company’s accounting policy is not to offset fair value amounts even when the terms of International Swap Dealers Association Master Agreements provide with the rights of setoff. The Company has not designated its derivative contracts as hedges for accounting purposes; therefore, all changes in fair value of the contracts are recorded in “Derivative fair value loss” in the accompanying Unaudited Consolidated Statement of Operations.


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The following table sets forth the volumes involved in the Company’s natural gas commodity derivative contracts and the weighted-average contractual prices per thousand cubic feet (“Mcf”) as of March 31, 2011:
 
                                         
    Daily Put
    Average
    Daily Swap
    Average
    Fair Value as of
 
Period
  Volumes     Price     Volumes     Price     March 31, 2011  
    (Mcf)     ($/Mcf)     (Mcf)     ($/Mcf)     (In thousands)  
 
April 2011 — December 2011
    14,000     $ 4.20       10,000     $ 4.30       976  
January 2012 — December 2012
    14,000     $ 4.90       10,000     $ 4.57       2,072  
January 2013 — December 2013
    12,000     $ 4.90       8,000     $ 5.00       2,031  
                                         
                                    $ 5,079  
                                         
 
The following tables set forth the volumes involved in the Company’s oil commodity derivative contracts and the weighted-average NYMEX prices per barrel (“Bbl”) as of March 31, 2011:
 
                                                                 
                                              Fair Value
 
    Daily
    Average
    Daily
    Average
    Average
    Daily
          as of
 
    Put
    Put
    Collar
    Collar
    Collar Cap
    Swap
    Average
    March 31,
 
Period
  Volumes     Price     Volumes     Put Price     Price     Volumes     Price     2011  
    (Bbls)     ($/Bbl)     (Bbls)     ($/Bbl)     ($/Bbl)     (Bbls)     ($/Bbl)     (In thousands)  
 
April 2011 — December 2011
    500     $ 92.00       180     $ 80.00     $ 94.60       350     $ 90.22       (2,130 )
January 2012 — December 2012
    500     $ 92.00       170     $ 81.00     $ 95.85       350     $ 92.40       (1,484 )
January 2013 — December 2013
        $       160     $ 82.00     $ 95.60       350     $ 92.71       (2,001 )
                                                                 
                                                            $ (5,615 )
                                                                 
 
The following table sets forth the volumes involved in the Company’s three-way oil commodity derivative collars and the weighted-average NYMEX prices per Bbl as of March 31, 2011:
 
                                         
                            Fair Value
 
          Average
    Average
    Average
    as of
 
    Daily
    Sub-Floor
    Floor
    Cap
    March 31,
 
Period
  Volumes     Price     Price     Price     2011  
    (Bbls)     ($/Bbl)     ($/Bbl)     ($/Bbl)     (In thousands)  
 
March 2011 — December 2011
    500     $ 67.50     $ 90.00     $ 110.00     $ (660 )
January 2012 — December 2012
    500     $ 67.50     $ 90.00     $ 110.00       (1,149 )
January 2013 — December 2013
    500     $ 67.50     $ 90.00     $ 110.00       (1,030 )
                                         
                                    $ (2,839 )
                                         
 
5.   Long-Term Debt
 
In December 2010, the Company entered into a five-year credit agreement with a bank syndicate comprised of Bank of America, N.A. and other lenders (the “Credit Agreement”). The Credit Agreement matures in December 2015.
 
The Credit Agreement provides for revolving credit loans to be made to the Company from time to time and letters of credit to be issued to the Company. The aggregate amount of loan commitments of the lenders under the Credit Agreement is $500 million. Availability under the Credit Agreement is subject to a borrowing base, which is redetermined semi-annually in May and November and upon requested special redeterminations. In February 2011, the Company Amended the Credit Agreement to increase the borrowing base from $95 million to $250 million. The borrowing base is


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
adjusted at the banks’ discretion and is based in part upon external factors over which the Company has no control.
 
As of March 31, 2011, there were $233 million in outstanding borrowings and $17 million of borrowing capacity under the Credit Agreement, while as of December 31, 2010, there were $52 million in outstanding borrowings and $43 million of borrowing capacity.
 
The Company incurs a commitment fee of 0.5% on the unused portion of the Credit Agreement.
 
Loans under the Credit Agreement are subject to varying rates of interest based on (i) the total outstanding borrowings in relation to the borrowing base and (ii) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin of 1.75% to 2.75% based on the ratio of outstanding borrowings to the borrowing base, and base rate loans bear interest at the base rate plus the applicable margin of 0.75% to 1.75% based on the ratio of outstanding borrowings to the borrowing base. The “Eurodollar rate” for any interest period (either one, two, three or six months, as selected by Enduro Sponsor or such longer period of up to twelve months as selected by Enduro Sponsor and consented to by the lenders) is the rate per year equal to the London Interbank Offered Rate (“LIBOR”), as published by Reuters or another source designated by Bank of America, N.A. for deposits in dollars for a similar interest period. The “base rate” is calculated as the highest of (i) the annual rate of interest announced by Bank of America, N.A. as its “prime rate,” (ii) the federal funds effective rate plus 0.5%, and (iii) the Eurodollar Rate (as defined in the Credit Agreement) for a one-month interest period plus 1.0%.
 
The Credit Agreement is secured by substantially all of the proved oil and natural gas properties of the Company and its subsidiaries.
 
The Credit Agreement contains several restrictive covenants including, among others:
 
  •  a prohibition against incurring debt, subject to permitted exceptions;
 
  •  a restriction on creating liens on the assets of the Company, subject to permitted exceptions;
 
  •  restrictions on merging and selling assets outside the ordinary course of business;
 
  •  a requirement to maintain a ratio of consolidated current assets to current liabilities (as defined in the Credit Agreement) of not less than 1.0 to 1.0; and,
 
  •  a requirement that the Company maintain a ratio of debt to annualized adjusted EBITDA (as defined in the Credit Agreement) of not more than 4.0 to 1.0, commencing with the quarter ending March 31, 2011.
 
Additionally, there is a limitation on the aggregate amount of forecasted oil and natural gas production that can be economically hedged with oil or natural gas derivative contracts.
 
The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the Credit Agreement to be immediately due and payable. As of March 31, 2011, the Company was in compliance with all its debt covenants.
 
The Company incurred costs of $3.4 million to obtain the Credit Agreement, which were capitalized and are presented as “Other assets” in the accompanying Consolidated Balance Sheet. These deferred loan costs are amortized over the 60-month life of the revolving credit facility. During the first quarter of 2011, the weighted average interest rate for total indebtedness was 3.0%.


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
6.   Asset Retirement Obligations
 
The Company’s asset retirement obligations relate to the future plugging and abandonment of wells and related facilities. The following table summarizes the Company’s asset retirement obligations for the three months ended March 31, 2011 (in thousands):
 
         
Asset retirement obligations — December 31, 2010
  $ 2,560  
Liabilities assumed at acquisition
    8,079  
Accretion of discount
    141  
         
Asset retirement obligations — March 31, 2011
  $ 10,780  
         
 
As of March 31, 2011, $9.6 million of the Company’s asset retirement obligations were long-term and are presented as “Asset retirement obligations, net of current portion” and $1.2 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheets. Accretion is included in “Other operating” in the accompanying Consolidated Statements of Operations.
 
7.   Members’ Equity
 
On April 9, 2010, the Company entered into an Operating Agreement with members of Enduro’s management and non-management investors. Under the terms of the Operating Agreement and subsequent amendments, a total of $465 million in capital was committed to the Company by Enduro’s management and the non-management investors.
 
At December 31, 2010, 282,160,500 Class A units and 96,000 Class B units were issued and outstanding. During the three months ended March 31, 2011, 182,699,500 of Class A and 500 of Class B were issued, respectively.
 
Class B Units are issued as incentive units and are subject to a forfeiture clause. Class B Units are fully vested as of the date of grant, but are ratably forfeited upon termination of the Class B member’s employment or engagement within three years of the date of grant and are subject to certain performance conditions. The incentive units are granted at the Board of Managers’ discretion. During 2010, the Company issued 96,000 units, and during the three months ended March 31, 2011, 500 units were issued. None of the 96,500 units issued have been forfeited.
 
The incentive units are subject to various performance and forfeiture provisions. Management has evaluated the terms of the awards and in particular the effect of the performance features on the potential value of the incentive units and has determined that any compensation expense during 2010 and during the three months ended March 31, 2011 would be nominal. Therefore, no compensation expense has been recognized. Should the performance features indicate that there is a significant value in the future, management will evaluate whether compensation expense should be recognized in the future.
 
8.   Commitments and Contingencies
 
                 General
 
The Company is subject to contingent liabilities with respect to existing or potential claims, lawsuits, and other proceedings, including those involving environmental, tax, and other matters, certain of which are discussed more specifically below. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters and its experience in contesting, litigating, and settling other matters. As the scope of the liabilities


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
becomes better defined, there will be changes in the estimates of future costs, which management currently believes will not have a material effect on the Company’s consolidated financial position, results of operations, or liquidity.
 
The Company regularly maintains cash balances at financial institutions. From time to time, these cash balances exceed the Federal Deposit Insurance Corporation insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on cash and cash equivalents.
 
                 Litigation
 
From time to time, the Company is a party to litigation or other legal proceedings that the Company considers to be a part of the ordinary course of business. The Company is not currently involved in any legal proceedings.
 
9.   Subsequent Events
 
The Company entered into additional oil commodity contracts in the second quarter of 2011. The following tables set forth the volumes involved in the Company’s oil commodity derivative contracts and the weighted-average NYMEX prices per barrel (“Bbl”) as of June 30, 2011:
 
                                                                 
    Daily
    Average
          Average
    Average
    Average
    Daily
       
    Put
    Put
    Daily
    Sub-Floor
    Floor
    Cap
    Swap
    Average
 
    Volumes
    Price
    Volumes
    Price
    Price
    Price
    Volumes
    Price
 
Period
  (Bbls)     ($/Bbl)     (Bbls)     ($/Bbl)     ($/Bbl)     ($/Bbl)     (Bbls)     ($/Bbl)  
 
2011
    500     $ 92.00       500     $ 67.50     $ 90.00     $ 110.00       530     $ 102.96  
2012
    500     $ 92.00       500     $ 67.50     $ 90.00     $ 110.00       520     $ 104.10  
2013
        $       500     $ 67.50     $ 90.00     $ 110.00       510     $ 102.97  
 
On May 3, 2011, the Company formed Enduro Royalty Trust (the “Trust”) pursuant to a Trust Agreement among Enduro Resource Partners LLC, as trustor, The Bank of New York Mellon Trust Company, N.A., as trustee, and Wilmington Trust Company, as Delaware trustee. The Trust was created to acquire and hold a net profits interest representing the right to receive 80% of the net profits from the sale of oil and natural gas production from certain properties in Texas, Louisiana and New Mexico held by the Company (the “Net Profits Interest”). The Company will convey, or cause to be conveyed, the Net Profits Interest to the Trust in exchange for all of the outstanding trust units of the Trust. The Company will sell a portion of its trust units in the initial public offering of the Trust’s trust units.


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Report of Independent Registered Public Accounting Firm
 
The Board of Managers and Members
Enduro Resource Partners LLC
 
We have audited the accompanying consolidated balance sheet of Enduro Resource Partners LLC (the Company) as of December 31, 2010, and the related consolidated statements of operations, changes in members’ equity, and cash flows for the period from March 3, 2010 (Inception) through December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Enduro Resource Partners LLC at December 31, 2010, and the consolidated results of its operations and its cash flows for the period from March 3, 2010 (Inception) through December 31, 2010, in conformity with U.S. generally accepted accounting principles.
 
/s/  Ernst & Young LLP
 
Fort Worth, Texas
May 13, 2011


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ENDURO RESOURCE PARTNERS LLC
 
CONSOLIDATED BALANCE SHEET
 
         
    December 31,
 
    2010  
    (In thousands,
 
    except unit
 
    amounts)  
 
ASSETS
Current assets:
       
Cash and cash equivalents
  $ 53,984  
Accounts receivable — trade
    7,215  
Prepaid expenses
    223  
Derivatives
    3,075  
         
Total current assets
    64,497  
         
Oil and natural gas properties — successful efforts method of accounting:
       
Proved properties
    209,723  
Unproved properties
    34,569  
Accumulated depletion, depreciation, and amortization
    (1,946 )
         
Total oil and natural gas properties, net
    242,346  
         
Other property and equipment, net
    184  
Acquisition deposits
    47,500  
Derivatives
    5,655  
Other
    1,650  
         
Total assets
  $ 361,832  
         
 
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
       
Accounts payable
  $ 786  
Accrued liabilities:
       
Lease operating
    1,667  
Development capital
    10,565  
Production taxes, transportation, and marketing
    748  
Derivatives
    1,044  
Current portion of firm transportation contract liability
    2,464  
Oil and natural gas revenues payable
    1,832  
Other
    2,576  
         
Total current liabilities
    21,682  
         
Long-term debt
    52,000  
Derivatives
    1,990  
Asset retirement obligations, net of current portion
    1,496  
Firm transportation contract liability, net of current portion and other
    10,725  
         
Total liabilities
    87,893  
         
Commitments and contingencies
       
Members’ equity:
       
Class A, 282,160,500 units issued and outstanding
    273,939  
Class B, 96,000 units issued and outstanding
     
         
Total members’ equity
    273,939  
         
Total liabilities and members’ equity
  $ 361,832  
         
 
The accompanying notes are an integral part of these consolidated financial statements.


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ENDURO RESOURCE PARTNERS LLC
 
CONSOLIDATED STATEMENT OF OPERATIONS
 
         
    March 3, 2010
 
    (Inception)
 
    Through
 
    December 31,
 
    2010  
    (In thousands,
 
    except per unit
 
    amounts)  
 
Revenues:
       
Oil
  $ 106  
Natural gas
    3,486  
Marketing
    383  
         
Total revenues
    3,975  
         
Expenses:
       
Lease operating
    507  
Production, ad valorem, and severance taxes
    170  
Gathering and transportation
    206  
Depletion, depreciation, and amortization
    1,973  
Marketing
    372  
General and administrative
    3,826  
Derivative fair value loss
    4,977  
Other operating
    18  
         
Total expenses
    12,049  
         
Operating loss
    (8,074 )
         
Interest expense, net
    (148 )
         
Net loss
  $ (8,222 )
         
Net loss per Class A unit — basic and diluted
  $ (0.06 )
Weighted average units outstanding — Class A:
       
Basic
    140,780  
Diluted
    140,780  
 
The accompanying notes are an integral part of these consolidated financial statements.


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ENDURO RESOURCE PARTNERS LLC
 
CONSOLIDATED STATEMENT OF CHANGES IN MEMBERS’ EQUITY
 
                 
          Members’
 
    Units     Equity  
    (In thousands, except units)  
 
Balance at March 3, 2010 (Inception)
          $  
Members’ contributions and issuance of Class A units
    282,160,500       282,161  
Issuance of Class B units
    96,000        
Net loss
            (8,222 )
                 
Balance at December 31, 2010
          $ 273,939  
                 
 
The accompanying notes are an integral part of these consolidated financial statements.


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ENDURO RESOURCE PARTNERS LLC
 
CONSOLIDATED STATEMENT OF CASH FLOWS
 
         
    March 3,
 
    2010
 
    (Inception)
 
    Through
 
    December 31,
 
    2010  
    (In thousands)  
 
Cash flows from operating activities:
       
Net loss
  $ (8,222 )
Adjustments to reconcile net loss to net cash used in operating activities:
       
Depletion, depreciation, and amortization
    1,973  
Unrealized loss on derivatives
    4,977  
Other non-cash items
    45  
Changes in operating assets and liabilities:
       
Accounts receivable
    (4,066 )
Prepaid expenses
    (223 )
Derivative assets
    (10,673 )
Accounts payable and other accrued expenses
    3,112  
         
Net cash used in operating activities
    (13,077 )
         
Cash flows from investing activities:
       
Acquisition deposits
    (47,500 )
Acquisition of oil and natural gas properties
    (217,736 )
Purchases of other property and equipment
    (186 )
         
Net cash used in investing activities
    (265,422 )
         
Cash flows from financing activities:
       
Contributions from members
    282,161  
Proceeds from long-term debt borrowings
    52,000  
Payment of deferred loan costs
    (1,678 )
         
Net cash provided by financing activities
    332,483  
         
Net increase in cash and cash equivalents
    53,984  
Cash and cash equivalents, beginning of period
     
         
Cash and cash equivalents, end of period
  $ 53,984  
         
Supplemental cash flow information:
       
Cash paid during the period for interest
  $ 134  
Non-cash investing and financing activities:
       
Properties acquired, other than for cash
  $ 83  
 
The accompanying notes are an integral part of these consolidated financial statements.


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
1.   Organization and Nature of Operations
 
Enduro Resource Partners LLC (together with its subsidiaries, “Enduro” or “the Company”), a Delaware limited liability company formed on March 3, 2010 (“Inception”), is engaged in the acquisition, exploration, development, and production of oil and natural gas from properties located in Texas and Louisiana.
 
2.   Summary of Significant Accounting Policies
 
Principles of Consolidation
 
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.
 
Use of Estimates
 
The preparation of financial statements in conformity with generally accepted accounting principles in the United States (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from those estimates.
 
Significant estimates made in preparing these consolidated financial statements include, among other things, the estimated quantities of proved oil and natural gas reserves used to calculate depletion of oil and natural gas properties; the estimated present value of future net cash flows used in evaluations of impairment and purchase price allocation; accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Changes in the assumptions utilized could have a significant impact on reported results in future periods.
 
Cash Equivalents
 
Cash and cash equivalents include cash on hand and depository accounts held by banks. The Company considers all highly liquid investments to be cash equivalents if they have original maturities of three months or less.
 
Accounts Receivable
 
The Company’s accounts receivable — trade is comprised of invoiced and accrued amounts from oil and natural gas sales. The Company reviews its outstanding accounts receivable balances based on the specific facts and circumstances of each outstanding amount and general economic conditions. The Company establishes an allowance for doubtful accounts equal to the estimable portion of accounts receivable for which failure to collect is considered probable. At December 31, 2010, the Company did not have an allowance for doubtful accounts balance based on the Company’s review of the collectibility of outstanding balances.
 
Oil and Natural Gas Properties
 
The Company follows the successful efforts method of accounting for its oil and natural gas properties. Under this method, all costs associated with productive and nonproductive development


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. Net capitalized costs of unproven property and exploration well costs are reclassified as proved property and well costs when related proved reserves are found.
 
Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive. If an exploration well is unsuccessful in finding proved reserves, the capitalized well costs are charged to exploration expense. The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheet following the completion of drilling unless both of the following conditions are met:
 
(i) The well has found a sufficient quantity of reserves to justify its completion as a producing well, and
 
(ii) The Company is making sufficient progress in assessing the reserves and the economic and operating viability of the project.
 
Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable.
 
Costs of significant nonproducing properties and exploratory wells in progress of being drilled are excluded from depletion until such time as the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.
 
The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. If an impairment loss is indicated by the carrying amount of the assets exceeding the sum of the undiscounted expected future net cash flows, then an impairment loss is recognized for the amount by which the carrying amount of the asset exceeds its estimated fair value. Estimates of the sum of expected future cash flows require management to estimate future recoverable proved and risk-adjusted probable and possible reserves, forecasts of future commodity prices, production and capital costs, and discount rates. Uncertainties about these future cash flow variables cause impairment estimates to be inherently imprecise.
 
Unproved oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. The impairment assessment is affected by the results of exploration activities, commodity price outlooks, planned future sales, or expiration of all or a portion of such projects. If the quantity of potential reserves determined by such evaluation is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at the time such determination is made.
 
Other Property and Equipment
 
Other property and equipment is carried at cost and consists of fixed assets, including office equipment, furniture and fixtures, and transportation equipment used in field operations. Depreciation is expensed on a straight-line basis over estimated useful lives, which range from 1 to 10 years, depending on its classification. During 2010, the Company recognized approximately $27,000 in depreciation expense for other property and equipment.
 
Asset Retirement Obligations
 
The Company records a liability for the fair value of an asset retirement obligation in the period in which it is incurred. For oil and natural gas properties, this is the period in which the property is


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
acquired or a new well is drilled. Asset retirement obligations are capitalized as part of the carrying values of the long-lived assets.
 
Asset retirement obligations are recorded at the present value of expected future net cash flows and are discounted using the Company’s credit adjusted risk free rate and then accreted until settled or sold, at which time the liability is reversed. Estimates are based on average plugging and abandonment well costs and estimated remaining field life based on reserve estimates.
 
Revenue Recognition
 
Sales of oil and natural gas are recognized when such products have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.
 
The Company sells oil and natural gas on a monthly basis. Virtually all of the Company’s contract pricing provisions are tied to a market index. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Accounts receivable — trade” in the accompanying Consolidated Balance Sheet.
 
The Company uses the sales method of accounting for oil and natural gas revenues, recognizing revenues based on the oil and natural gas delivered rather than its working interest share of oil and natural gas produced.
 
The Company had no material imbalances as of December 31, 2010.
 
Marketing revenues derived from sales of oil or natural gas purchased from third parties are recognized when persuasive evidence of a sales arrangement exists, delivery has occurred, the sales price is fixed or determinable, and collectibility is reasonably assured. As the Company takes title to the oil and natural gas and has risks and rewards of ownership, these transactions are presented gross in marketing revenue and marketing expense in the accompanying Consolidated Statement of Operations, unless they meet the criteria for netting.
 
Income Taxes
 
The Company is organized as a limited liability company and is classified as a partnership for federal income tax purposes. Due to its partnership classification, the Company is not subject to federal income tax. Similarly, most states treat entities classified as partnerships for federal income tax purposes as partnerships for state purposes. As such, income tax liabilities are passed through to the partners. Texas imposes an entity-level tax on all forms of business regardless of federal entity classification. The Company’s current year Texas tax liability was not material. Accordingly, no income tax expense has been recorded in the financial statements.
 
Derivatives
 
The Company uses derivative financial instruments to reduce exposure to commodity price fluctuations. These transactions are primarily in the form of swap contracts, put options, and collars with large financial institutions, all of which are lenders underwriting the Company’s revolving credit facility.
 
Derivative instruments are recorded at fair value and included on the Consolidated Balance Sheet as assets or liabilities. The Company has not designated its derivative contracts as hedges for


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Table of Contents

ENDURO RESOURCE PARTNERS LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
accounting purposes; therefore, all changes in fair value of the contracts are recorded in “Derivative fair value loss” in the accompanying Consolidated Statement of Operations.
 
Segments
 
The Company has significant operations in only one industry segment and one geographic operating segment, that being the oil and natural gas exploration and production industry in the United States of America.
 
Recently Issued Accounting Pronouncements
 
The following discussion provides information about new accounting pronouncements that were issued by the Financial Accounting Standards Board (“FASB”) during 2010:
 
In September 2006, the FASB issued guidance to define fair value, establish a framework for measuring fair value, and to enhance disclosures about fair value measures required under other accounting pronouncements. In January 2010, the FASB issued guidance to (i) require separate disclosure of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers, (ii) require separate disclosure of purchases, sales, issuances, and settlements in the reconciliation for fair value measurements using significant unobservable inputs (Level 3), (iii) clarify the level of disaggregation for fair value measurements of assets and liabilities, and (iv) clarify disclosures about inputs and valuation techniques used to measure fair values for both recurring and nonrecurring fair value measurements. The Company adopted this guidance at Inception; thus, it did not affect the Company’s financial position, results of operations, or liquidity. See Note 4 for additional information regarding the Company’s fair value measurements.
 
3.   Acquisition
 
On December 1, 2010, the Company completed an acquisition of oil and natural gas properties in East Texas and North Louisiana from Denbury Resources, Inc. (the “Denbury Acquisition”). These properties constitute all of the Company’s oil and gas assets as of December 31, 2010.
 
Total consideration paid for the properties at closing was $213.8 million after preliminary closing adjustments. The Company funded the acquisition through member capital contributions and borrowings under its revolving credit facility. The Denbury Acquisition was accounted for as a business and recorded at fair value, which was determined using a risk-adjusted discounted cash flow analysis. The purchase price allocation for the acquisition is preliminary and subject to revision pending finalization of closing adjustments.


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The following table presents a summary of the preliminary fair value of assets acquired and liabilities assumed at the acquisition date (in thousands):
 
         
Oil and natural gas properties
  $ 241,634  
Other equipment
    24  
Accounts receivable
    4,950  
         
Total assets acquired
    246,608  
         
Asset retirement obligations
    (2,542 )
Firm transportation contract liability
    (13,762 )
Operating payables
    (16,543 )
         
Total liabilities assumed
    (32,847 )
         
Fair value of net assets acquired
  $ 213,761  
         
 
Operating payables in the above table include suspended revenues payable of $1.8 million. The operations of the properties acquired above have been included in the Company’s results of operations since the date of closing. The Company incurred $0.4 million of expenses in connection with the acquisition, which is recorded in “General and administrative” expense in the accompanying Consolidated Statement of Operations.
 
Unaudited Pro Forma Acquisition Information
 
Had the Denbury Acquisition occurred on March 3, 2010, the Company’s pro forma revenue and net loss for the period from Inception through December 31, 2010 would have been as follows (in thousands):
 
         
Pro forma revenues
  $ 44,186  
Pro forma net loss
    (3,467 )
 
4.   Disclosures About Fair Value Measurements
 
Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:
 
  •      Level 1 — Unadjusted quoted prices are available for identical assets or liabilities in active markets.
 
  •      Level 2 — Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates); and inputs derived principally from or corroborated by observable market data by correlation or other means.
 
  •      Level 3 — Unobservable inputs for the asset or liability.
 
The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level of input that is significant to the measurement in its entirety.


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The Company has classified its derivative contracts into one of the three levels based upon the data relied upon to determine the fair value. The fair values are based upon quotes obtained from counterparties to the derivative contracts. The Company reviews other readily available market prices for its derivative contracts as there is an active market for these contracts; however, the Company does not have access to specific valuation models used by the counterparties. Included in these models are discount factors that the Company must estimate in its calculation. The Company’s swap contracts are classified as Level 2, while its floors and collars are classified as Level 3.
 
The following tables set forth the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2010 (in thousands):
 
                                 
        Fair Value Measurements at Reporting Date Using
        Quoted Prices in
  Significant
   
        Active Markets
  Other
  Significant
    Fair Value at
  for Identical
  Observable
  Unobservable
    December 31,
  Assets
  Inputs
  Inputs
    2010   (Level 1)   (Level 2)   (Level 3)
 
Oil and natural gas derivative contracts — assets
  $ 8,730     $      —     $ 143     $ 8,587  
Oil and natural gas derivative contracts — liabilities
    3,034             2,328       706  
 
The following table presents the changes in fair values of the Company’s financial instruments measured using significant unobservable inputs (Level 3) during 2010 (in thousands):
 
                 
    Derivative Contracts — Floors
 
    and Caps  
    Oil     Natural Gas  
 
Balance at Inception
  $     $  
Purchases
    4,713       5,960  
Unrealized losses included in earnings
    (1,716 )     (1,076 )
                 
Balance at December 31, 2010
  $ 2,997     $ 4,884  
                 
 
The following table presents the carrying amounts and fair values of the Company’s financial instruments as of December 31, 2010 (in thousands):
 
                 
    Carrying Value     Fair Value  
 
Financial assets:
               
Natural gas commodity contracts — current asset
  $ 1,639     $ 1,639  
Oil commodity contracts — current asset
    1,436       1,436  
Natural gas commodity contracts — long-term asset
    3,386       3,386  
Oil commodity contracts — long-term asset
    2,269       2,269  
Financial liabilities:
               
Natural gas commodity contracts — current liabilities
    333       333  
Oil commodity contracts — current liabilities
    711       711  
Natural gas commodity contracts — long-term liabilities
    1,120       1,120  
Oil commodity contracts — long-term liabilities
    870       870  
Long-term debt
    52,000       52,000  


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The Company has other financial instruments consisting primarily of cash and cash equivalents, accounts receivable, other current assets, and accounts payable that approximate fair value due to the short maturity of these instruments.
 
Long-Term Debt
 
The carrying amount of bank debt approximates fair value because these instruments bear interest at variable market rates, which approximates the current market rates as of December 31, 2010.
 
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
 
The Denbury Acquisition was recorded at fair value, which was determined using a risk-adjusted discounted cash flow. The fair value of oil and natural gas properties is based on significant inputs not observable in the market. Key assumptions include (i) NYMEX oil and natural gas futures prices, which are observable, (ii) projections of the estimated quantities of oil and natural gas reserves, including those classified as proved, probable, and possible, (iii) projections of future rates of production, (iv) timing and amount of future development and operating costs, (v) projected recovery factors, and (vi) risk-adjusted discount rates.
 
Asset retirement obligations are recorded at fair value. Unobservable inputs are used in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered Level 3 measurements in the fair value hierarchy.
 
The Company’s review of oil and natural gas impairment involves estimation of fair values. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and natural gas properties are based on (i) proved reserves and risk-adjusted probable and possible reserves, (ii) commodity price outlook, which would be used by purchasers, including assumptions as to inflation of costs and expenses, and (iii) the estimated discount rate that would be used by purchasers to assess the fair value of the assets. Through December 31, 2010, the Company has not recognized any impairments.
 
Concentrations of Credit Risk
 
At December 31, 2010, the Company’s primary concentrations of credit risk are related to its derivative obligations. The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of setoff upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. The Company’s accounting policy is to not offset fair value amounts for derivative instruments.


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures. The following table provides the Company’s derivative assets and liabilities by counterparty as of December 31, 2010 (in thousands):
 
                 
Counterparty
  Assets     Liabilities  
 
Credit Agricole
  $ 929     $ 1,040  
BNP Paribas
    2,675       661  
Bank of America Merrill Lynch
    5,126       1,333  
                 
Total
  $ 8,730     $ 3,034  
                 
 
5.   Derivative Financial Instruments
 
The Company uses derivative financial instruments to reduce exposure to commodity price fluctuations.
 
The following table sets forth the volumes involved in the Company’s natural gas commodity derivative contracts and the weighted-average contractual prices per thousand cubic feet (“Mcf”) as of December 31, 2010:
 
                                         
                            Fair Value at
 
    Daily Put
    Average
    Daily Swap
    Average
    December 31,
 
Period   Volumes     Price     Volumes     Price     2010  
    (Mcf)     ($/Mcf)     (Mcf)     ($/Mcf)     (In thousands)  
 
January 2011 — February 2011
    12,000     $ 4.19       10,000     $ 4.30     $ 190  
March 2011 — December 2011
    13,000     $ 4.18       10,000     $ 4.30       1,116  
January 2012 — December 2012
    13,000     $ 4.92       10,000     $ 4.57       1,875  
January 2013 — December 2013
    2,000     $ 4.95       5,000     $ 5.10       391  
                                         
                                    $ 3,572  
                                         
 
The following tables set forth the volumes involved in the Company’s oil commodity derivative contracts and the weighted-average NYMEX prices per barrel (“Bbl”) as of December 31, 2010:
 
                                                                 
                      Average
    Average
                   
    Daily
    Average
    Daily
    Collar
    Collar
    Daily
          Fair Value at
 
    Put
    Put
    Collar
    Put
    Cap
    Swap
    Average
    December 31,
 
Period   Volumes     Price     Volumes     Price     Price     Volumes     Price     2010  
    (Bbls)     ($/Bbl)     (Bbls)     ($/Bbl)     ($/Bbl)     (Bbls)     ($/Bbl)     (In thousands)  
 
January 2011 — February 2011
        $       180     $ 80.00     $ 94.60       150     $ 85.50     $ 744  
March 2011 — December 2011
    500     $ 92.00       180     $ 80.00     $ 94.60       150     $ 85.50       (395 )
January 2012 — December 2012
    500     $ 92.00       170     $ 81.00     $ 95.85       150     $ 88.60       1,466  
January 2013 — December 2013
        $       160     $ 82.00     $ 95.60       150     $ 90.00       (337 )
                                                                 
                                                            $ 1,478  
                                                                 


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The following table sets forth the volumes involved in the Company’s three-way oil commodity derivative collars and the weighted-average NYMEX prices per Bbl as of December 31, 2010:
 
                                         
          Average
    Average
    Average
    Fair Value at
 
    Daily
    Sub-Floor
    Floor
    Cap
    December 31,
 
Period   Volumes     Price     Price     Price     2010  
    (Bbls)     ($/Bbl)     ($/Bbl)     ($/Bbl)     (In thousands)  
 
March 2011 — December 2011
    500     $ 67.50     $ 90.00     $ 110.00     $ 376  
January 2012 — December 2012
    500     $ 67.50     $ 90.00     $ 110.00       212  
January 2013 — December 2013
    500     $ 67.50     $ 90.00     $ 110.00       58  
                                         
                                    $ 646  
                                         
 
6.   Long-Term Debt
 
In December 2010, the Company entered into a five-year credit agreement with a bank syndicate comprised of Bank of America, N.A. and other lenders (the “Credit Agreement”). The Credit Agreement matures in December 2015.
 
The Credit Agreement provides for revolving credit loans to be made to the Company from time to time and letters of credit to be issued to the Company. The aggregate amount of loan commitments of the lenders under the Credit Agreement is $500 million. Availability under the Credit Agreement is subject to a borrowing base of $95 million, which is redetermined semi-annually in May and November and upon requested special redeterminations. The borrowing base is adjusted at the banks’ discretion and is based in part upon external factors over which the Company has no control. At December 31, 2010, there were $52 million in outstanding borrowings and $43 million of borrowing capacity under the Credit Agreement.
 
The Company incurs a commitment fee of 0.5% on the unused portion of the Credit Agreement.
 
Loans under the Credit Agreement are subject to varying rates of interest based on (i) the total outstanding borrowings in relation to the borrowing base and (ii) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin of 1.75% to 2.75% based on the ratio of outstanding borrowings to the borrowing base, and base rate loans bear interest at the base rate plus the applicable margin of 0.75% to 1.75% based on the ratio of outstanding borrowings to the borrowing base. The “Eurodollar rate” for any interest period (either one, two, three or six months, as selected by Enduro Sponsor or such longer period of up to twelve months as selected by Enduro Sponsor and consented to by the lenders) is the rate per year equal to the London Interbank Offered Rate (“LIBOR”), as published by Reuters or another source designated by Bank of America, N.A. for deposits in dollars for a similar interest period. The “base rate” is calculated as the highest of (i) the annual rate of interest announced by Bank of America, N.A. as its “prime rate,” (ii) the federal funds effective rate plus 0.5%, and (iii) the Eurodollar Rate (as defined in the Credit Agreement) for a one-month interest period plus 1.0%.
 
The Credit Agreement is secured by substantially all of the proved oil and natural gas properties of the Company and its subsidiaries.
 
The Credit Agreement contains several restrictive covenants including, among others:
 
  •      a prohibition against incurring debt, subject to permitted exceptions;
 
  •      a restriction on creating liens on the assets of the Company, subject to permitted exceptions;


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
  •      restrictions on merging and selling assets outside the ordinary course of business;
 
  •      consolidated current assets to current liabilities (as defined in the Credit Agreement) of not less than 1.0 to 1.0; and,
 
  •      a requirement that the Company maintain a ratio of debt to annualized adjusted EBITDA (as defined in the Credit Agreement) of not more than 4.0 to 1.0, commencing with the quarter ending March 31, 2011.
 
Additionally, there is a limitation on the aggregate amount of forecasted oil and natural gas production that can be economically hedged with oil or natural gas derivative contracts.
 
The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the Credit Agreement to be immediately due and payable. At December 31, 2010, the Company was in compliance with all its debt covenants.
 
The Company incurred costs of $1.7 million to obtain the Credit Agreement, which were capitalized and are presented as “Other assets” in the accompanying Consolidated Balance Sheet. These deferred loan costs are amortized over the 60-month life of the revolving credit facility. During 2010, the weighted average interest rate for total indebtedness was 4.0%.
 
7.   Asset Retirement Obligations
 
The Company’s asset retirement obligations relate to the future plugging and abandonment of wells and related facilities. The following table summarizes the Company’s asset retirement obligations for the period ended December 31, 2010 (in thousands):
 
         
Asset retirement obligations at March 3, 2010 (Inception)
  $  
Liabilities assumed at acquisition
    2,542  
Accretion of discount
    18  
         
Asset retirement obligations at December 31, 2010
  $ 2,560  
         
 
As of December 31, 2010, $1.5 million of the Company’s asset retirement obligations were long-term and are presented as “Asset retirement obligations, net of current portion” and $1.1 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheet. Accretion is included in “Other operating” in the accompanying Consolidated Statement of Operations.
 
8.   Members’ Equity
 
On April 9, 2010, the Company entered into an Operating Agreement with members of Enduro’s management and non-management investors. Under the terms of the Operating Agreement and subsequent amendments, a total of $465 million in capital was committed to the Company by Enduro’s management and the non-management investors.
 
At December 31, 2010, 282,160,500 Class A units and 96,000 Class B units were issued and outstanding. Additional capital contributions to Enduro may be initiated pursuant to the terms of the Operating Agreement entered into by Enduro’s management and non-management investors. Each investor has agreed to contribute additional capital upon call by Enduro. Capital calls may be initiated by Enduro on an as-needed basis for acquisitions or general corporate purposes.
 
Class B Units are issued as incentive units and are subject to a forfeiture clause. Class B Units are fully vested as of the date of grant, but are ratably forfeited upon termination of the Class B


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
member’s employment or engagement within three years of the date of grant and are subject to certain performance conditions. The incentive units are granted at the Board of Managers’ discretion. During 2010, the Company issued 96,000 units, of which none have been forfeited.
 
The incentive units are subject to various performance and forfeiture provisions. Management has evaluated the terms of the awards and in particular the effect of the performance features on the potential value of the incentive units and has determined that any compensation expense during 2010 would be nominal. Therefore, no compensation expense has been recognized in 2010. Should the performance features indicate that there is a significant value in the future, management will evaluate whether compensation expense should be recognized in the future.
 
9.   Commitments and Contingencies
 
General
 
The Company is subject to contingent liabilities with respect to existing or potential claims, lawsuits, and other proceedings, including those involving environmental, tax, and other matters, certain of which are discussed more specifically below. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters and its experience in contesting, litigating, and settling other matters. As the scope of the liabilities becomes better defined, there will be changes in the estimates of future costs, which management currently believes will not have a material effect on the Company’s consolidated financial position, results of operations, or liquidity.
 
The Company regularly maintains cash balances at financial institutions. From time to time, these cash balances exceed the Federal Deposit Insurance Corporation insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on cash and cash equivalents.
 
Litigation
 
From time to time, the Company is a party to litigation or other legal proceedings that the Company considers to be a part of the ordinary course of business. The Company is not currently involved in any legal proceedings.
 
Lease Agreements
 
The Company leases office facilities in Fort Worth under operating leases. Rental expenses associated with these operating leases during 2010 were approximately $50,000 and are included in “General and administrative expense” in the accompanying Consolidated Statement of Operations. The following table summarizes the remaining non-cancelable future payments under these operating leases as of December 31, 2010 (in thousands):
 
         
2011
  $ 287  
2012
    417  
2013
    443  
2014
    733  
2015
    685  
Thereafter
    507  
         
    $ 3,072  
         


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Firm Transportation Agreement
 
As part of the Denbury Acquisition, the Company assumed a 10-year firm transportation contract. The Company is committed to transport 22,500 million British thermal units (“MMBtu”) per day of natural gas for a minimum transportation fee of $0.30 per MMBtu. During 2010, no oil and natural gas volumes were transported under this agreement; however, the minimum transportation fee for daily volumes totaled $0.2 million. The Company has not currently designated any oil and natural gas volumes to fulfill this commitment.
 
The following table summarizes the remaining non-cancelable future payments under this firm transportation contract as of December 31, 2010 (in thousands):
 
         
2011
  $ 2,464  
2012
    2,470  
2013
    2,464  
2014
    2,464  
2015
    2,464  
Thereafter
    10,059  
         
    $ 22,385  
         
 
10.   Major Customers
 
During 2010, the Company sold approximately 53% of its share of oil and natural gas production to Spark Energy. During 2010, the Company received 21% of its oil and natural gas revenues from Petrohawk Energy Corporation and 14% from Chesapeake Operating, Inc. Management believes that the loss of any of these purchasers would not have an adverse effect on the ability of the Company to sell its oil and natural gas production. However, it is possible that the loss of any one of these customers could have an adverse effect on the price the Company receives for its oil and natural gas sales.
 
11.   Related-Party Transactions
 
During 2010, the Company reimbursed non-management investors approximately $0.2 million for legal and travel expenses incurred.
 
12.   Subsequent Events
 
In January 2011, the Company acquired oil and natural gas properties for $133.8 million after preliminary closing adjustments located in the Permian Basin of New Mexico and West Texas. The effective date of this acquisition was October 1, 2010. In February 2011, the Company acquired additional oil and natural gas properties for $314.2 million after preliminary closing adjustments located in the Permian Basin of New Mexico and West Texas. The effective date of the February acquisition was November 1, 2010. The acquisitions were funded with borrowings under the Company’s revolving credit facility and member contributions. Subsequent to year-end, the Company received $182.7 million in capital contributions. As of December 31, 2010, the Company had recorded $47.5 million related to these acquisitions as shown in the accompanying Consolidated Balance Sheet as “Acquisition deposits.”
 
Subsequent to December 31, 2010, the Company’s borrowing base was redetermined in conjunction with the 2011 acquisitions. As of May 12, 2011, the Company’s borrowing base was $250 million, of which $235 million was drawn.


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
13.   Supplemental Oil and Natural Gas Disclosures (Unaudited)
 
Costs Incurred for Oil and Natural Gas Producing Activities
 
         
    Inception Through
 
    December 31, 2010  
    (In thousands)  
 
Proved acquisitions
  $ 207,123  
Unproved acquisitions
    34,569  
         
Total acquisitions
    241,692  
Development costs
    2,600  
         
Total costs incurred
  $ 244,292  
         
 
Reserve Quantity Information
 
The estimates of the Company’s proved reserves as of December 31, 2010, which are located in East Texas and North Louisiana in the United States were prepared by Cawley, Gillespie & Associates, Inc., an independent petroleum engineering firm. Proved reserves were estimated in accordance with rules and regulations established by the Securities and Exchange Commission (“SEC”) and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements.
 
Estimates of reserves as of December 31, 2010 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on the first day of each month within the applicable fiscal 12-month period. Using this method, NYMEX oil prices of $79.43 per barrel and NYMEX natural gas prices of $4.37 per MMBtu were used in the reserve estimates as of December 31, 2010.
 
Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing, and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of newly acquired properties or new discoveries are more imprecise than those on currently producing oil and natural gas properties that have been owned and operated for a longer time. Accordingly, these estimates are expected to change as additional information becomes available in the future.


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The following table provides a rollforward of total proved reserves from Inception through December 31, 2010, as well as total proved developed and undeveloped reserves as of the beginning and end of the period. Oil volumes are expressed in thousands of barrels (“MBbls”), gas volumes are expressed in thousands of Mcf (“MMcf”) and total volumes are expressed in thousands of barrels of oil equivalent (“MBOE”).
 
                         
    Inception through December 31, 2010  
    Oil     Natural Gas     Total  
    (MBbls)     (MMcf)     (MBOE)  
 
Total proved reserves
                       
Balance as of March 3, 2010 (Inception)
                 
Purchases of minerals-in-place
    27       99,289       16,575  
Production
    (1 )     (853 )     (143 )
                         
Balance as of December 31, 2010
    26       98,436       16,432  
                         
Total proved developed reserves
                       
Balance as of March 3, 2010 (Inception)
                 
Balance as of December 31, 2010
    26       63,848       10,667  
Proved undeveloped reserves
                       
Balance as of March 3, 2010 (Inception)
                 
Balance as of December 31, 2010
          34,588       5,765  
 
Standardized Measure of Discounted Future Net Cash Flows
 
The standardized measure of discounted future net cash flows (“Standardized Measure”) is computed by applying commodity prices used in determining proved reserves (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows. Since the Company is not subject to federal income taxes, future income taxes have been excluded.
 
Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and natural gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future commodity prices, interest rates, changes in development and production costs, and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.
 
The following tables provide the Standardized Measure of discounted future cash flows as of December 31, 2010, as well as a rollforward in total for the period (in thousands):
 
         
Oil and natural gas producing activities:
       
Future cash inflows
  $ 394,848  
Future production costs
    (98,627 )
Future development costs
    (55,634 )
         
Undiscounted future net cash flows
    240,587  
10% annual discount factor
    (113,190 )
         
Standardized measure of discounted future cash flows
  $ 127,397  
         


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ENDURO RESOURCE PARTNERS LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves (in thousands):
 
         
Standardized measure balance as of March 3, 2010 (Inception)
  $  
Oil and natural gas sales, net of production costs
    (2,709 )
Previously estimated development costs incurred
    2,600  
Purchases of minerals-in-place
    127,506  
         
Standardized measure balance as of December 31, 2010
  $ 127,397  
         


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ENDURO SPONSOR
 
UNAUDITED PRO FORMA FINANCIAL STATEMENTS
 
Introduction
 
The following unaudited pro forma financial statements have been prepared to illustrate: (i) the acquisition by Enduro Resource Partners LLC and its predecessor (collectively, “Enduro Sponsor”) of properties in East Texas and North Louisiana from Denbury Resources Inc. (the “Predecessor Properties”) and of properties in Texas and New Mexico from Samson Investment Company and ConocoPhillips Company (the “Acquired Properties”); (ii) the conveyance of the Net Profits Interest in the Underlying Properties by Enduro Sponsor to Enduro Royalty Trust (the “Trust”); (iii) the sale of trust units to the public; (iv) the repayment of a portion of outstanding borrowings under Enduro Sponsor’s revolving credit facility and (v) the distribution of a portion of proceeds to Enduro Sponsor’s sole member, Enduro Resource Holdings LLC. The unaudited pro forma balance sheet is presented as of March 31, 2011, giving effect to the sale of 13,200,000 trust units at $           per unit, the Net Profits Interest conveyance, the repayment of a portion of Enduro Sponsor’s revolving credit facility, and a distribution to Enduro Sponsor’s sole member, Enduro Resource Holdings LLC with the net proceeds of the sale of the trust units as if they occurred on March 31, 2011. The unaudited pro forma statements of operations present the historical statements of operations of Enduro Sponsor for the three months ended March 31, 2011 and for the year ended December 31, 2010 (consisting of the period from March 3, 2010 (“Inception”) through December 31, 2010, the historical statements of Enduro Resource Partners LLC Predecessor for the periods from January 1 through March 8, 2010 and from March 9 through November 30, 2010), giving effect to the acquisition of the Predecessor Properties and the Acquired Properties, and to the Net Profits Interest conveyance and the repayment of a portion of Enduro Sponsor’s revolving credit facility as if they occurred as of January 1, 2010 reflecting only pro forma adjustments expected to have a continuing impact on the combined results.
 
These unaudited pro forma financial statements are for informational purposes only. They do not purport to present the results that would have actually occurred had the acquisitions, the offering of trust units, the Net Profits Interest conveyance, the repayment of a portion of borrowings under Enduro Sponsor’s revolving credit facility, and the distribution to the sole member of Enduro Sponsor been completed on the assumed dates or for the periods presented. Moreover, they do not purport to project Enduro Sponsor’s financial position or results of operations for any future date or period.
 
To produce the pro forma financial statements, Enduro Sponsor’s management made certain estimates. These estimates are based on the most recently available information. To the extent there are significant changes in these amounts, the assumptions and estimates herein could change significantly. The unaudited pro forma financial statements should be read in conjunction with the accompanying notes to such unaudited pro forma financial statements, “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Enduro Sponsor” and the audited historical financial statements of Enduro Sponsor and Enduro Resource Partners LLC Predecessor included in this prospectus and elsewhere in the registration statement.


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ENDURO SPONSOR
 
UNAUDITED PRO FORMA BALANCE SHEET
(in thousands)
 
 
                         
    March 31, 2011  
          Offering
    Pro Forma
 
    Historical     Adjustments     As Adjusted  
 
Assets
                       
Current assets:
                       
Cash and cash equivalents
  $ 1,956     $ 97,000 (b)   $ 98,956  
Accounts receivable — trade
    21,841             21,841  
Prepaid expenses
    438             438  
Derivatives
    2,615             2,615  
                         
Total current assets
    26,850       97,000       123,850  
                         
Oil and natural gas properties — successful efforts method of accounting:
                       
Proved properties
    677,439       (173,020 )(c)     504,419  
Unproved properties
    35,046             35,046  
Accumulated depletion, depreciation, and amortization
    (12,759 )     3,043 (c)     (9,716 )
                         
Total oil and natural gas properties, net
    699,726       (169,977 )(c)     529,749  
                         
Other property and equipment, net
    226             226  
Derivatives
    5,726             5,726  
Other
    3,278             3,278  
                         
Total assets
  $ 735,806     $ (72,977 )   $ 662,829  
                         
Liabilities and members’ equity
                       
Current liabilities:
                       
Accounts payable
  $ 2,629     $     $ 2,629  
Accrued liabilities:
                       
Lease operating
    3,541             3,541  
Development capital
    8,922             8,922  
Production taxes, transportation, and marketing
    1,367             1,367  
Derivatives
    4,882             4,882  
Current portion of firm transportation contract liability
    2,471             2,471  
Oil and natural gas revenues payable
    723             723  
Other
    5,736             5,736  
                         
Total current liabilities
    30,271             30,271  
                         
Long-term debt
    233,000       (183,000 )(b)     50,000  
Derivatives
    6,834             6,834  
Asset retirement obligations, net of current portion
    9,599             9,599  
Firm transportation contract liability, net of current portion
    10,844             10,844  
Other
    115             115  
                         
Total liabilities
    290,663       (183,000 )     107,663  
                         
Members’ equity:
                       
Class A, 464,860,000 units issued and outstanding
    445,143       130,023 (d)     555,166  
              (20,000 )(b)        
Class B, 96,500 units issued and outstanding
                 
                         
Total members’ equity
    445,143       110,023       555,166  
                         
Total liabilities and members’ equity
  $ 735,806     $ (72,977 )   $ 662,829  
                         
 
The accompanying notes are an integral part of these unaudited pro forma financial statements.


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ENDURO SPONSOR
 
UNAUDITED PRO FORMA STATEMENT OF OPERATIONS
(in thousands)
 
                                         
    Three Months Ended March 31, 2011  
          ConocoPhillips
    Pro Forma After
             
    Enduro
    Permian Basin
    Acquisition
    Offering
    Pro Forma As
 
    Sponsor     Assets(a)     Adjustments     Adjustments     Adjusted  
 
Revenues:
                                       
Oil
  $ 10,236     $ 9,966     $ 20,202     $ (1,559 )   $ 18,643  
Natural gas
    11,899       875       12,774       (562 )     12,212  
Marketing
    817             817             817  
                                         
Total revenues
    22,952       10,841       33,793       (2,121 )(h)     31,672  
                                         
Expenses:
                                       
Lease operating
    4,007       2,820       6,827             6,827  
Production, ad valorem, and severance taxes
    1,447       883       2,330             2,330  
Gathering and transportation
    794       41       835             835  
Depletion, depreciation, and amortization
    10,830       3,963 (e)     14,793       (3,636 )(i)     11,157  
Marketing
    795             795             795  
General and administrative
    3,043       463 (f)     3,506             3,506  
Derivative fair value loss
    11,449             11,449             11,449  
Other operating
    896       137 (g)     1,033             1,033  
                                         
Total expenses
    33,261       8,307       41,568       (3,636 )     37,932  
                                         
Operating income (loss)
    (10,309 )     2,534       (7,775 )     1,515       (6,260 )
Interest expense, net
    (1,220 )     (598 )(k)     (1,818 )     1,443 (j)     (375 )
                                         
Income (loss) before income taxes
    (11,529 )     1,936       (9,593 )     2,958       (6,635 )
Deferred income tax benefit
    34             34             34  
                                         
Net income (loss)
  $ (11,495 )   $ 1,936     $ (9,559 )   $ 2,958     $ (6,601 )
                                         
 
The accompanying notes are an integral part of these unaudited pro forma financial statements.


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ENDURO SPONSOR
 
 
                                                                                     
    Year Ended December 31, 2010  
    Enduro
      Predecessor -
      Predecessor -
                         
    Sponsor       DNR       EAC                                            
    Inception
      March 9
      January 1
    Acquisition Adjustments     Pro Forma
             
    Through
      Through
      Through
    Samson
    ConocoPhillips
    Other
    Total
    After
             
    December 31,
      November 30,
      March 8,
    Permian Basin
    Permian Basin
    Acquisition
    Acquisition
    Acquisition
    Offering
    Pro Forma As
 
    2010       2010       2010     Assets(a)     Assets(a)     Adjustments     Adjustments     Adjustments     Adjustments     Adjusted  
Revenues:
                                                                                   
Oil
  $ 106       $ 1,036       $ 331     $ 16,626     $ 52,062     $     $ 68,688     $ 70,161     $ (6,942 )   $ 63,219  
Natural gas
    3,486         35,503         10,756       5,650       7,025             12,675       62,420       (3,349 )     59,071  
Marketing
    383         3,671         1,077                               5,131             5,131  
                                                                                     
Total revenues
    3,975         40,210         12,164       22,276       59,087             81,363       137,712       (10,291 )(h)     127,421  
                                                                                     
Expenses:
                                                                                   
Lease operating
    507         5,285         1,142       3,428       16,657             20,085       27,019             27,019  
Production, ad valorem, and severance taxes
    170         2,003         548       1,702       4,994             6,696       9,417             9,417  
Gathering and transportation
    206         2,755         429       212       243             455       3,845             3,845  
Depletion, depreciation, and amortization
    1,973         21,754         7,949       10,694 (e)     24,877 (e)     (29,703 )(e)     33,047       64,723       (15,382 )(i)     49,341  
                                                  27,179 (e)                                
Exploration expense
            9,957         231                               10,188             10,188  
Marketing
    372         3,588         1,060                               5,020             5,020  
General and administrative
    3,826         1,254         2,481       1,273 (f)     2,908 (f)           4,181       11,742             11,742  
Merger-related transaction costs
            6,922         16,136                   (23,058 )(k)     (23,058 )                  
Derivative fair value loss
    4,977                                               4,977             4,977  
Other operating
    18         24         9       86 (g)     823 (g)     (g)     909       960             960  
                                                                                     
Total expenses
    12,049         53,542         29,985       17,395       50,502       (25,582 )     42,315       137,891       (15,382 )     122,509  
                                                                                     
Operating income (loss)
    (8,074 )       (13,332 )       (17,821 )     4,881       8,585       25,582       39,048       (179 )     5,091       4,912  
                                                                                     
Interest expense, net
    (148 )       (6,183 )             (1,796 )(j)     (4,768 )(j)     6,183 (j)     (2,135 )     (8,466 )     6,471 (j)     (1,995 )
                                                  (1,754 )(j)                                
                                                                                     
Net income (loss)
  $ (8,222 )     $ (19,515 )     $ (17,821 )   $ 3,085     $ 3,817     $ 30,011     $ 36,913     $ (8,645 )   $ 11,562     $ 2,917  
                                                                                     
                                                                                     
 
The accompanying notes are an integral part of these unaudited pro forma financial statements.


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ENDURO SPONSOR
 
NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS
 
1.   Basis of Presentation
 
Enduro Sponsor will convey, or cause to be conveyed, the Net Profits Interest in certain oil and natural gas producing properties located in Texas, Louisiana, and New Mexico (the “Underlying Properties”) to Enduro Royalty Trust (the “Trust”). The Net Profits Interest entitles the Trust to receive 80% of the net profits attributable to Enduro Sponsor’s interest from the sale of oil and natural gas production from the Underlying Properties.
 
In exchange for the conveyance of the Net Profits Interest, Enduro Sponsor will receive 33,000,000 trust units. The unaudited pro forma balance sheet assumes Enduro Sponsor will sell 13,200,000 of the trust units at $      per unit and will incur estimated direct transaction costs of approximately $30.0 million (comprised of underwriter, legal, accounting and other fees).
 
Enduro Sponsor will recognize a gain on the sale of the units representing the difference between the net proceeds of the offering and the historical cost of the Net Profits Interest conveyed.
 
The net proceeds of the offering will be used to repay a portion of the outstanding borrowings under Enduro Sponsor’s revolving credit facility, to make a distribution to its sole member, Enduro Resource Holdings LLC, and to acquire additional oil and natural gas properties. Enduro Sponsor has not yet identified oil and natural gas properties to be acquired.
 
2.   Pro Forma Adjustments
 
Pro forma adjustments are necessary to reflect the acquisition of the Acquired Properties, the Net Profits Interest conveyance to the Trust and related issuance of the trust units, the sale of trust units to the public, the repayment of a portion of outstanding borrowings under Enduro Sponsor’s revolving credit facility, and a distribution to Enduro Sponsor’s sole member using proceeds from the offering. The pro forma adjustments included in the unaudited pro forma financial statements are as follows:
 
(a) Pro forma adjustments necessary to record the acquisition of the Acquired Properties as if such acquisitions occurred on January 1, 2010 and the related oil and natural gas revenues and related expenses.
 
In January 2011, Enduro Sponsor acquired oil and natural gas properties in the Permian Basin of West Texas and New Mexico for $133.8 million after preliminary closing adjustments. In February 2011, Enduro Sponsor acquired additional oil and natural gas properties located in the Permian Basin for approximately $314.2 million after preliminary closing adjustments. The acquisitions were funded with borrowings under Enduro Sponsor’s revolving credit facility and equity contributions from Enduro Sponsor’s members. These acquisitions are included in the historical unaudited consolidated balance sheet of Enduro Sponsor as of March 31, 2011.
 
The pro forma adjustments included in the unaudited pro forma balance sheet are as follows:
 
                 
  (b )  
Gross cash proceeds from the sale of trust units
  $ 330,000  
       
Repayment of a portion of outstanding borrowings on revolving credit facility
    (183,000 )
       
Distribution to sole member of Enduro Sponsor
    (20,000 )
       
Payment of underwriting discount, structuring fee and other offering expenses
    (30,000 )
                 
       
  Cash proceeds remaining
  $ 97,000  
                 
 
Enduro Sponsor will make an estimated distribution to its sole member as shown above to cover estimated tax liabilities in connection with the formation of the Trust.


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ENDURO SPONSOR
 
NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS — (Continued)
 
                 
  (c )   Reduction of oil and natural gas properties due to conveyance of Net Profits Interest:        
        Historical cost of Underlying Properties   $ 550,925  
        Less: Asset retirement obligations     (10,237 )
                 
        Property to be conveyed to the Trust     540,688  
        Multiplied by percentage allocable to Net Profits Interest     80 %
                 
        Historical cost of oil and natural gas properties to be conveyed to the Trust     432,550  
        Multiplied by portion of trust units sold to the public     40 %
                 
        Reduction of oil and natural gas proved properties due to conveyance of Net Profits Interest to the Trust   $ 173,020  
                 
        Accumulated depletion, depreciation, and amortization of Underlying Properties   $ (9,510 )
        Multiplied by percentage allocable to Net Profits Interest     80 %
                 
        Accumulated depletion, depreciation, and amortization of oil and natural gas properties to be conveyed to the Trust     (7,608 )
        Multiplied by portion of trust units sold to the public     40 %
                 
        Reduction of accumulated depletion, depreciation, and amortization due to conveyance of Net Profits Interest to the Trust   $ (3,043 )
                 
  (d )   Gain on sale of Net Profits Interest calculated as follows:        
        Gross cash proceeds from the sale of trust units   $ 330,000  
        Less: Net book value of conveyed Net Profits Interest     (424,942 )
        Plus: Enduro Sponsor retained interest in trust units (60%)     254,965  
        Payment of underwriting discounts, structuring fees and other offering expenses     (30,000 )
                 
        Gain on sale of units   $ 130,023  
                 
 
The gain on sale of units has been excluded from the unaudited pro forma statements of operations as the item is non-recurring.
 
The pro forma adjustments included in the unaudited pro forma statements of operations are as follows:
 
(e) For the Acquired Assets, depletion, depreciation, and amortization expense was recorded based on units of production utilizing an estimated unit rate based on proved reserves. In addition, a pro forma adjustment was recorded to depletion, depreciation, and amortization expense for the unaudited pro forma statement of operations for the year ended December 31, 2010 to adjust the amounts recorded by Enduro Resource Partners LLC Predecessor to be consistent with the rates used by Enduro Sponsor as if the properties had been owned by Enduro Sponsor since January 1, 2010.
 
In December 2010, Enduro Sponsor completed the acquisition of oil and natural gas properties in East Texas and North Louisiana from Denbury Resources Inc. (“Denbury”). Denbury had owned such properties since March 9, 2010 when Denbury merged with Encore Acquisition Company (the “Merger”). As a result, the properties were owned by three different entities during 2010, and the pro forma adjustment to depletion, depreciation, and amortization was recorded consistent with Enduro Sponsor’s methodology.


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ENDURO SPONSOR
 
NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS — (Continued)
 
(f) General and administrative expenses were recorded as if the Acquired Properties had been owned by Enduro Sponsor for the full year ended December 31, 2010 based on historical general and administrative expenses per barrel of oil equivalent production.
 
(g) Pro forma adjustments were recorded for accretion expense of asset retirement obligations of the Acquired Properties for the three months ended March 31, 2011 and the year ended December 31, 2010.
 
                     
        Three Months
    Year Ended
 
        Ended March 31,
    December 31,
 
        2011     2010  
 
(h)
  Calculation of net profits:                
    Revenues of the Underlying Properties —                
   
Oil
  $ 20,150     $ 70,033  
   
Natural gas
    7,262       33,787  
                     
   
Total revenues
    27,412       103,820  
                     
   
Direct operating expenses of the Underlying Properties —
               
   
Lease operating
    6,185       24,579  
   
Gathering and processing
    489       1,977  
   
Production and other taxes
    2,005       8,069  
                     
   
Total direct operating expenses
    8,679       34,625  
    Development costs     12,105       37,036  
                     
    Total expenses and development costs     20,784       71,661  
                     
    Net profits     6,628       32,159  
    Multiplied by percentage allocable to Net Profits Interest     80 %     80 %
                     
    Net profits to Trust from Net Profits Interest     5,302       25,727  
    Multiplied by portion of trust units sold to the public     40 %     40 %
                     
   
Reduction in Enduro Sponsor’s total revenues due to Net Profits Interest of public unitholders
  $ 2,121     $ 10,291  
                     
 
As the Net Profits Interest burdens the conveyed properties with no obligation by the holder to pay expenses, the Net Profits Interest is treated as a royalty payment, with the associated amount shown as a reduction of Enduro Sponsor’s revenues.
 
                     
        Three Months
    Year Ended
 
        Ended March 31,
    December 31,
 
        2011     2010  
 
(i)
  Reduce depreciation on assets conveyed to Trust   $ (3,636 )   $ (15,382 )
 
(j) Interest expense adjustments reflect borrowings under the revolving credit facility for the purchase of the Acquired Properties and the subsequent repayment of a portion of outstanding borrowings with proceeds from the offering of trust units. For the three months ended March 31, 2011, Enduro Sponsor’s weighted average interest rate was approximately 3.0%, and for the year ended December 31, 2010, Enduro Sponsor’s weighted average interest rate was approximately 4.0%.
 
(k) In connection with the Merger of Denbury and Encore Acquisition Company, certain related transaction costs were allocated to Enduro Resource Partners LLC Predecessor in the historical carve out statements of operations. These expenses are not related to the ongoing operations of Enduro Sponsor and are not reflective of expenses that would have been incurred if the properties had been owned by Enduro Sponsor for the year ended December 31, 2010.


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Cawley, Gillespie & Associates, Inc.
 
PETROLEUM CONSULTANTS
 
         
9601 AMBERGLEN BLVD., SUITE 117
  306 WEST SEVENTH STREET, SUITE 302   1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1106
  FORT WORTH, TEXAS 76102-4987   HOUSTON, TEXAS 77002-5008
512-249-7000
  817-336-2461   713-651-9944
    www.cgaus.com    
 
January 27, 2011
 
Mr. John W. Arms
COO Executive Vice President
Enduro Resource Partners LLC
777 Main St., Suite 800
Fort Worth, TX 76102
 
         
    Re:   Evaluation Summary
        Enduro Resource Partners LLC Interests
        Total Proved Reserves
        Texas and Louisiana Properties
        As of December 31, 2010
         
        Pursuant to the Guidelines of the
        Securities and Exchange Commission for
        Reporting Corporate Reserves and
        Future Net Revenue
         
 
Dear Mr. Arms:
 
As requested, this report was prepared on January 27, 2011 for Enduro Resource Partners LLC (the “Company”) for the purpose of submitting our summary level reserve estimates and economic forecasts attributable to the Company interests. We evaluated 100% of the Company reserves, which are made up of various oil and gas properties in Texas and Louisiana. This report, with an effective date of December 31, 2010, was prepared using constant prices and costs and conforms to the guidelines of the Securities and Exchange Commission (SEC).
 
Composite forecasts for the Total Proved, Proved Developed Producing, Proved Developed Non-Producing and Proved Undeveloped estimates are presented by category in Tables I-TP, I-PDP, I-PDNP and I-PUD, respectively. The “II” Tables present estimates of ultimate recovery, gross and net reserves, ownership, revenue, expenses, investments, net income and discounted cash flow at ten percent for the individual properties which are listed alphabetically by lease name for each category.


ANNEX A-1-1


Table of Contents

The proved reserves and economics by category are summarized as follows:
 
                                     
              Proved
             
        Proved
    Developed
             
        Developed
    Non-
    Proved
    Total
 
        Producing     Producing     Undeveloped     Proved  
       
 
 
Net Reserves
                                   
Oil
  - Mbbl     25.6       0.0       0.0       25.6  
Gas
  - MMcf     53,065.5       10,782.2       34,588.2       98,435.9  
Revenue
                                   
Oil
  - M   $ 1,974.7       0.0       0.0       1,974.7  
Gas
  - M   $ 211,574.7       40,971.5       140,327.7       392,873.9  
Severance Taxes
  - M   $ 7,760.1       862.9       3,225.3       11,848.3  
Ad Valorem Taxes
  - M   $ 4,312.9       802.2       2,742.0       7,857.1  
Operating Expenses
  - M   $ 55,531.1       4,619.7       12,032.0       72,182.8  
Investments
  - M   $ 0.0       3,738.2       51,896.0       55,634.2  
Net Operating Income (BFIT)
  - M   $ 145,945.3       30,948.6       70,432.3       247,326.2  
Discounted at 10%
  - M   $ 90,223.2       19,610.5       20,391.0       130,224.8  
 
Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.
 
Our estimates are for proved reserves only and do not include any probable or possible reserves nor have any values been attributed to interest in acreage beyond the location for which undeveloped reserves have been estimated.
 
Hydrocarbon Pricing
 
The base oil and gas prices calculated for December 31, 2010 were $79.43/bbl and $4.37/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices during 2010 and the base gas price is based upon Henry Hub spot prices during 2010.
 
The base prices were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $76.34 per barrel for oil and $4.65 per MCF for gas. All economic factors were held constant in accordance with SEC guidelines.
 
Economic Parameters
 
Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, gas shrinkage, ad valorem taxes, lease operating expenses and investments were calculated and prepared by Enduro Resource Partners LLC and were thoroughly reviewed by us for accuracy and completeness. Lease operating expenses, price differentials and gas shrinkage were determined at the well level using 12-month averages. Ad valorem tax percentages were determined at the well level by comparing taxes paid to total revenue.


ANNEX A-1-2


Table of Contents

Possible Effects of Federal and State Legislation
 
Federal, state and local laws and regulations, which are currently in effect and that govern the development and production of oil and natural gas, have been considered in the evaluation of proved reserves for this report. However, the impact of possible changes to legislation or regulations to future operating expenses and investment costs have not been included in the evaluation. These possible changes could have an effect on the reserves and economics. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.
 
SEC Conformance and Regulations
 
The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 1 and 2 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.
 
Reserve Estimation Methods
 
The methods employed in estimating reserves are described in page 3 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to offset production, both of which are considered to provide a relatively high degree of accuracy.
 
Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for Enduro Resource Partners LLC properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.
 
General Discussion
 
The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.
 
An on-site field inspection of the properties has not been performed nor have the mechanical operation or condition of the wells and their related facilities been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included.


ANNEX A-1-3


Table of Contents

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. This evaluation was prepared by Robert D. Ravnaas, Executive Vice President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #61304). We do not own an interest in the properties or Enduro Resource Partners LLC and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.
 
Yours very truly,
 
Cawley, Gillespie & Associates, Inc.
Texas Registered Engineering Firm F-693
 
 
Robert D. Ravnaas, P. E.
Executive Vice President


ANNEX A-1-4


Table of Contents

APPENDIX
Explanatory Comments for Summary Tables
 
HEADINGS
 
Table I
Description of Table Information
Identity of Interest Evaluated
Property Description — Location
Reserve Classification and Development Status
Effective Date of Evaluation
 
FORECAST
 
     
(Columns)
   
(1)(11)(21)
  Calendar or Fiscal years/months commencing on effective date.
(2)(3)(4)
  Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.
(5)(6)(7)
  Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage.
(8)
  Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
(9)
  Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
(10)
  Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.
(12)
  Revenue derived from oil sales — column (5) times column (8).
(13)
  Revenue derived from gas sales — column (6) times column (9).
(14)
  Revenue derived from NGL sales — column (7) times column (10).
(15)
  Revenue derived from hedge positions.
(16)
  Total Revenue — sum of column (12) through column (15).
(17)
  Production-Severance taxes deducted from gross oil, gas and NGL revenue.
(18)
  Revenue after taxes — column (16) less column (17).
(19)
  Ad Valorem taxes.
(20)
  $/MCFE6 — is the total of column (22), column (25), column (26), and column (27) divided by MCF Gas Equivalent (“MCFE”). MCFE is net gas production column (6) plus net oil production column (5) converted to gas at one bbl oil per six Mcf gas plus net NGL production column (7) converted to gas at one bbl NGL per 3.9 Mcf gas.
(22)
  Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS.
(23)
  Average gross wells.
(24)
  Average net wells are gross wells times working interest.
(25)
  Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
(26)
  3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
(27)
  Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.


ANNEX A-1-5


Table of Contents

     
(28)
  Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
(29)(30)
  Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered.
(31)
  Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.
 
MISCELLANEOUS
 
     
DCF Profile
 
•   The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns (30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile.
Life
 
•   The economic life of the appraised property is noted in the lower right-hand corner of the table.
Footnotes
 
•   Comments regarding the evaluation may be shown in the lower left-hand footnotes.
Price Deck
 
•   A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes.

ANNEX A-1-6


Table of Contents

APPENDIX
Methods Employed in the Estimation of Reserves
 
The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.
 
Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.
 
A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:
 
Production performance.  This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as “decline curve” analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.
 
Material balance.  This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.
 
Volumetric.  This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.


ANNEX A-1-7


Table of Contents

Analogy.  This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.
 
Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.


ANNEX A-1-8


Table of Contents

APPENDIX
Reserve Definitions and Classifications
 
The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:
 
“(22) Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
 
“(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
 
“(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
 
“(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
 
“(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
 
“(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
 
“(6) Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
 
“(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
 
“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
“(31) Undeveloped oil and gas reserves.  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.


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“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
 
“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
 
“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
 
“(18) Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
 
“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
 
“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
 
“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
 
“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).
 
“(17) Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
 
“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
 
“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
 
“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
 
“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
 
“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.


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“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”
 
Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S-K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”
 
“(26) Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
 
Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”


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Cawley, Gillespie & Associates, Inc.
 
PETROLEUM CONSULTANTS
 
         
9601 AMBERGLEN BLVD., SUITE 117
  306 WEST SEVENTH STREET, SUITE 302   1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1106
  FORT WORTH, TEXAS 76102-4987   HOUSTON, TEXAS 77002-5008
512-249-7000
  817-336-2461   713-651-9944
    www.cgaus.com    
 
February 24, 2011
 
Mr. John W. Arms
COO Executive Vice President
Enduro Resource Partners LLC
777 Main St., Suite 800
Fort Worth, TX 76102
 
         
    Re:   Evaluation Summary
        Enduro Resource Partners LLC Interests
        Pro Forma Samson Non-Operated Acquisition of
         Permian Properties by Enduro Resource Partners
         Using Yearend SEC Prices as of December 31, 2010
        Proved Developed Producing Reserves
        Texas and New Mexico Properties
        As of December 31, 2010
        Pursuant to the Guidelines of the
Securities and Exchange Commission for
Reporting Corporate Reserves and
Future Net Revenue
         
 
Dear Mr. Arms:
 
As requested, this report was prepared on February 24, 2011 for Enduro Resource Partners LLC (the “Company”) for the purpose of submitting our summary level reserve estimates and economic forecasts attributable to the Company interests. We evaluated 100% of the Company reserves, which are made up of various oil and gas properties in Texas and New Mexico. This report, with an effective date of December 31, 2010, was prepared using constant prices and costs and conforms to the guidelines of the Securities and Exchange Commission (SEC).
 
Composite forecasts for Proved Developed Producing estimates are presented by category in Table I-PDP. The “II” Table presents estimates of ultimate recovery, gross and net reserves, ownership, revenue, expenses, investments, net income and discounted cash flow at ten percent for the individual properties which are listed alphabetically by lease name.


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The proved reserves and economics by category are summarized as follows:
 
             
        Proved
 
        Developed
 
        Producing  
       
 
 
Net Reserves
           
Oil
  - Mbbl     3,047.8  
Gas
  - MMcf     10,780.7  
Revenue
           
Oil
  - M$     237,652.0  
Gas
  - M$     54,600.6  
Severance Taxes
  - M$     17,159.8  
Ad Valorem Taxes
  - M$     7,301.9  
Operating Expenses
  - M$     82,910.5  
Net Operating Income (BFIT)
  - M$     184,880.4  
Discounted at 10%
  - M$     84,954.0  
 
Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.
 
Our estimates are for proved reserves only and do not include any probable or possible reserves nor have any values been attributed to interest in acreage beyond the location for which undeveloped reserves have been estimated.
 
Hydrocarbon Pricing
 
The base oil and gas prices calculated for December 31, 2010 were $79.43/bbl and $4.37/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices during 2010 and the base gas price is based upon Henry Hub spot prices during 2010.
 
The base prices were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $76.34 per barrel for oil and $4.65 per MCF for gas. All economic factors were held constant in accordance with SEC guidelines.
 
Economic Parameters
 
Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, gas shrinkage, ad valorem taxes, lease operating expenses and investments were calculated and prepared by Enduro Resource Partners LLC and were thoroughly reviewed by us for accuracy and completeness. Lease operating expenses, price differentials and gas shrinkage were determined at the well level using 12-month averages. Ad valorem tax percentages were determined at the well level by comparing taxes paid to total revenue.
 
Possible Effects of Federal and State Legislation
 
Federal, state and local laws and regulations, which are currently in effect and that govern the development and production of oil and natural gas, have been considered in the evaluation of proved reserves for this report. However, the impact of possible changes to legislation or regulations to future operating expenses and investment costs have not been included in the evaluation. These possible changes could have an effect on the reserves and economics. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.


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SEC Conformance and Regulations
 
The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 1 and 2 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.


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Reserve Estimation Methods
 
The methods employed in estimating reserves are described in page 3 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to offset production, both of which are considered to provide a relatively high degree of accuracy.
 
Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for Enduro Resource Partners LLC properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.
 
General Discussion
 
The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.
 
An on-site field inspection of the properties has not been performed nor have the mechanical operation or condition of the wells and their related facilities been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included.
 
Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. This evaluation was prepared by Robert D. Ravnaas, Executive Vice President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #61304). We do not own an interest in the properties or Enduro Resource Partners LLC and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.
 
Yours very truly,
 
Cawley, Gillespie & Associates, Inc.
Texas Registered Engineering Firm F-693
 
 
Robert D. Ravnaas, P. E.
Executive Vice President


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APPENDIX
Explanatory Comments for Summary Tables
 
HEADINGS
 
Table I
Description of Table Information
Identity of Interest Evaluated
Property Description — Location
Reserve Classification and Development Status
Effective Date of Evaluation
 
FORECAST
 
     
(Columns)
   
(1)(11)(21)
  Calendar or Fiscal years/months commencing on effective date.
(2)(3)4)
  Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.
(5)(6)(7)
  Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage.
(8)
  Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
(9)
  Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
(10)
  Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.
(12)
  Revenue derived from oil sales — column (5) times column (8).
(13)
  Revenue derived from gas sales — column (6) times column (9).
(14)
  Revenue derived from NGL sales — column (7) times column (10).
(15)
  Revenue derived from hedge positions.
(16)
  Total Revenue — sum of column (12) through column (15).
(17)
  Production-Severance taxes deducted from gross oil, gas and NGL revenue.
(18)
  Revenue after taxes — column (16) less column (17).
(19)
  Ad Valorem taxes.
(20)
  $/MCFE6 — is the total of column (22), column (25), column (26), and column (27) divided by MCF Gas Equivalent (“MCFE”). MCFE is net gas production column (6) plus net oil production column (5) converted to gas at one bbl oil per six Mcf gas plus net NGL production column (7) converted to gas at one bbl NGL per 3.9 Mcf gas.
(22)
  Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS.
(23)
  Average gross wells.
(24)
  Average net wells are gross wells times working interest.
(25)
  Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
(26)
  3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
(27)
  Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.


ANNEX A-2-5


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(28)
  Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
(29)(30)
  Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered.
(31)
  Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.
 
MISCELLANEOUS
 
     
DCF Profile
 
•   The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns (30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile.
Life
 
•   The economic life of the appraised property is noted in the lower right-hand corner of the table.
Footnotes
 
•   Comments regarding the evaluation may be shown in the lower left-hand footnotes.
Price Deck
 
•   A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes.

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APPENDIX
Methods Employed in the Estimation of Reserves
 
The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy.  Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.
 
Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.
 
A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:
 
Production performance.  This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as “decline curve” analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.
 
Material balance.  This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.
 
Volumetric.  This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.


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Analogy.  This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.
 
Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.


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APPENDIX
Reserve Definitions and Classifications
 
The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:
 
“(22) Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
 
“(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
 
“(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
 
“(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
 
“(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
 
“(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
 
“(6) Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
 
“(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
 
“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
“(31) Undeveloped oil and gas reserves.  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.


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“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
 
“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
 
“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
 
“(18) Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
 
“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
 
“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
 
“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
 
“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).
 
“(17) Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
 
“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
 
“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
 
“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
 
“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
 
“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.


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“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”
 
Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S-K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”
 
“(26) Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
 
“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”


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Cawley, Gillespie & Associates, Inc.
 
PETROLEUM CONSULTANTS
 
         
9601 AMBERGLEN BLVD., SUITE 117
  306 WEST SEVENTH STREET, SUITE 302   1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1106
  FORT WORTH, TEXAS 76102-4987   HOUSTON, TEXAS 77002-5008
512-249-7000
  817-336-2461   713-651-9944
    www.cgaus.com    
 
March 16, 2011
 
Mr. John W. Arms
COO Executive Vice President
Enduro Resource Partners LLC
777 Main St., Suite 800
Fort Worth, TX 76102
 
         
    Re:   Evaluation Summary
        Enduro Resource Partners LLC Interests
        Pro Forma Conoco Phillips Acquisition of
  Permian Properties by Enduro Resource Partners
  Using Yearend SEC Prices as of December 31, 2010
        Total Proved Reserves
        Texas and New Mexico Properties
        As of December 31, 2010
        Pursuant to the Guidelines of the
Securities and Exchange Commission for
Reporting Corporate Reserves and
Future Net Revenue
         
 
Dear Mr. Arms:
 
As requested, this report was prepared on March 16, 2011 for Enduro Resource Partners LLC (the “Company”) for the purpose of submitting our summary level reserve estimates and economic forecasts attributable to the Company interests. We evaluated 100% of the Company reserves, which are made up of various oil and gas properties in Texas and New Mexico. This report, with an effective date of December 31, 2010, was prepared using constant prices and costs and conforms to the guidelines of the Securities and Exchange Commission (SEC).
 
Composite forecasts for the Total Proved, Proved Developed Producing and Proved Undeveloped estimates are presented by category in Tables I-TP, I-PDP and I-PUD, respectively. The “II” Tables present estimates of ultimate recovery, gross and net reserves, ownership, revenue, expenses, investments, net income and discounted cash flow at ten percent for the individual properties which are listed alphabetically by lease name for each category.


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The proved reserves and economics by category are summarized as follows:
 
                             
        Proved
             
        Developed
    Proved
    Total
 
        Producing     Undeveloped     Proved  
       
 
 
Net Reserves
                           
Oil
  - Mbbl     9,131.2       379.2       9,510.4  
Gas
  - MMcf     9,406.4       1,293.4       10,699.8  
NGL
        182.7       0.0       182.7  
Revenue
                           
Oil
  - M$     692,325.1       28,715.3       721,040.4  
Gas
  - M$     51,748.6       7,496.6       59,245.2  
NGL
        8,536.6       0.0       8,536.6  
Severance Taxes
  - M$     41,604.2       1,883.1       43,487.3  
Ad Valorem Taxes
  - M$     21,520.4       1,201.5       22,721.9  
Operating Expenses
  - M$     335,279.8       5,721.4       341,001.1  
Other Deductions
  - M$     719.8       44.3       764.1  
Investments
  - M$     0.0       6,000.0       6,000.0  
Net Operating Income (BFIT)
  - M$     353,486.3       21,361.5       374,847.8  
Discounted at 10%
  - M$     183,955.8       11,064.8       195,020.5  
 
Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.
 
Our estimates are for proved reserves only and do not include any probable or possible reserves nor have any values been attributed to interest in acreage beyond the location for which undeveloped reserves have been estimated.
 
Hydrocarbon Pricing
 
The base oil and gas prices calculated for December 31, 2010 were $79.43/bbl and $4.37/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices during 2010 and the base gas price is based upon Henry Hub spot prices during 2010.
 
The base prices were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $76.34 per barrel for oil and $4.65 per MCF for gas. All economic factors were held constant in accordance with SEC guidelines.
 
Economic Parameters
 
Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, gas shrinkage, ad valorem taxes, lease operating expenses and investments were calculated and prepared by Enduro Resource Partners LLC and were thoroughly reviewed by us for accuracy and completeness. Lease operating expenses, price differentials and gas shrinkage were determined at the well level using 12-month averages. Ad valorem tax percentages were determined at the well level by comparing taxes paid to total revenue.


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Possible Effects of Federal and State Legislation
 
Federal, state and local laws and regulations, which are currently in effect and that govern the development and production of oil and natural gas, have been considered in the evaluation of proved reserves for this report. However, the impact of possible changes to legislation or regulations to future operating expenses and investment costs have not been included in the evaluation. These possible changes could have an effect on the reserves and economics. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.
 
SEC Conformance and Regulations
 
The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 1 and 2 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.
 
Reserve Estimation Methods
 
The methods employed in estimating reserves are described in page 3 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to offset production, both of which are considered to provide a relatively high degree of accuracy.
 
Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for Enduro Resource Partners LLC properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.
 
General Discussion
 
The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.
 
An on-site field inspection of the properties has not been performed nor have the mechanical operation or condition of the wells and their related facilities been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included.


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Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. This evaluation was prepared by Robert D. Ravnaas, Executive Vice President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #61304). We do not own an interest in the properties or Enduro Resource Partners LLC and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.
Yours very truly,
 
Cawley, Gillespie & Associates, Inc.
Texas Registered Engineering Firm F-693
 
 
Robert D. Ravnaas, P. E.
Executive Vice President


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APPENDIX
Explanatory Comments for Summary Tables
 
HEADINGS
 
Table I
Description of Table Information
Identity of Interest Evaluated
Property Description — Location
Reserve Classification and Development Status
Effective Date of Evaluation
 
FORECAST
 
     
(Columns)
   
(1)(11)(21)
  Calendar or Fiscal years/months commencing on effective date.
(2)(3)(4)
  Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.
(5)(6)(7)
  Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage.
(8)
  Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
(9)
  Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
(10)
  Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.
(12)
  Revenue derived from oil sales — column (5) times column (8).
(13)
  Revenue derived from gas sales — column (6) times column (9).
(14)
  Revenue derived from NGL sales — column (7) times column (10).
(15)
  Revenue derived from hedge positions.
(16)
  Total Revenue — sum of column (12) through column (15).
(17)
  Production-Severance taxes deducted from gross oil, gas and NGL revenue.
(18)
  Revenue after taxes — column (16) less column (17).
(19)
  Ad Valorem taxes.
(20)
  $/MCFE6 — is the total of column (22), column (25), column (26), and column (27) divided by MCF Gas Equivalent (“MCFE”). MCFE is net gas production column (6) plus net oil production column (5) converted to gas at one bbl oil per six Mcf gas plus net NGL production column (7) converted to gas at one bbl NGL per 3.9 Mcf gas.
(22)
  Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS.
(23)
  Average gross wells.
(24)
  Average net wells are gross wells times working interest.
(25)
  Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
(26)
  3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
(27)
  Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.


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(28)
  Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
(29)(30)
  Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered.
(31)
  Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.
 
MISCELLANEOUS
 
     
DCF Profile
 
•   The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns (30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile.
Life
 
•   The economic life of the appraised property is noted in the lower right-hand corner of the table.
Footnotes
 
•   Comments regarding the evaluation may be shown in the lower left-hand footnotes.
Price Deck
 
•   A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes.

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APPENDIX
Methods Employed in the Estimation of Reserves
 
The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.
 
Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.
 
A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:
 
Production performance.  This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as “decline curve” analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.
 
Material balance.  This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.
 
Volumetric.  This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.


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Analogy.  This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.
 
Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.


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APPENDIX
Reserve Definitions and Classifications
 
The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:
 
“(22) Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
 
“(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
 
“(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
 
“(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
 
“(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
 
“(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
 
“(6) Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
 
“(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
 
“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
“(31) Undeveloped oil and gas reserves.  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.


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“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
 
“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
 
“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
 
“(18) Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
 
“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
 
“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
 
“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
 
“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).
 
“(17) Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
 
“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
 
“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
 
“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
 
“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
 
“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.


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“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”
 
Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S — K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”
 
“(26) Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
 
Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”


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Cawley, Gillespie & Associates, Inc.
 
PETROLEUM CONSULTANTS
 
         
9601 AMBERGLEN BLVD., SUITE 117
  306 WEST SEVENTH STREET, SUITE 302   1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1106
  FORT WORTH, TEXAS 76102-4987   HOUSTON, TEXAS 77002-5008
512-249-7000
  817-336-2461   713-651-9944
    www.cgaus.com    
 
March 31, 2011
 
Mr. John W. Arms
COO Executive Vice President
Enduro Resource Partners LLC
777 Main St., Suite 800
Fort Worth, TX 76102
 
         
Re:
  Pro Forma Evaluation   Pursuant to the Guidelines of the
    Enduro Resource Partners LLC Interests   Securities and Exchange Commission for
    Total Proved Reserves for the Underlying Properties   Reporting Corporate Reserves and
      of Enduro Royalty Trust Total Controlled Interests   Future Net Revenue
    Texas, Louisiana and New Mexico Properties    
    Using Yearend SEC Prices as of December 31, 2010    
 
Dear Mr. Arms:
 
As requested, this report was prepared on March 31, 2011 for Enduro Resource Partners LLC (“Company”) for the purpose of submitting our estimates of total proved reserves and forecasts of economics attributable to the underlying properties. We evaluated 100% of the reserves in the underlying properties, which are made up of oil and gas properties in Texas, Louisiana and New Mexico owned by the Company. This evaluation utilized an effective date of December 31, 2010, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (SEC). A composite summary of the proved reserves is presented below.
 
                                     
              Proved
             
        Proved
    Developed
             
        Developed
    Non-
    Proved
    Total
 
        Producing     Producing     Undeveloped     Proved  
       
 
 
Net Reserves
                                   
Oil
  - Mbbl     12,204.3       0.0       379.2       12,583.6  
Gas
  - MMcf     48,494.9       2,798.0       34,494.5       85,787.4  
NGL
  - Mbbl     182.7       0.0       0.0       182.7  
Revenue
                                   
Oil
  - M$     931,928.0       0.0       28,715.3       960,643.3  
Gas
  - M$     221,463.6       11,360.0       142,714.5       375,538.1  
NGL
  - M$     8,536.6       0.0       0.0       8,536.6  
Severance Taxes
  - M$     63,314.4       229.1       4,997.1       68,540.5  
Ad Valorem Taxes
  - M$     31,269.6       222.6       3,843.6       35,335.8  
Operating Expenses
  - M$     455,929.7       944.1       17,263.6       474,137.3  
Investments
  - M$     0.0       2,429.9       55,243.9       57,673.7  
Net Operating Income (BFIT)
  - M$     611,414.5       7,534.4       90,081.7       709,030.5  
Discounted at 10%
  - M$     313,925.7       4,401.8       31,204.4       349,531.9  


ANNEX B-1


Table of Contents

Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.
 
The oil reserves include oil and condensate. Oil volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base.
 
Our estimates are for proved reserves only and do not include any probable or possible reserves nor have any values been attributed to interest in acreage beyond the location for which undeveloped reserves have been estimated.
 
Hydrocarbon Pricing
 
The base SEC oil and gas prices calculated for December 31, 2010 were $79.43/bbl and $4.37/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices (EIA) during 2010 and the base gas price is based upon Henry Hub spot prices (EIA) during 2010.
 
The base prices were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $76.34 per barrel for oil and $4.65 per MCF for gas. All economic factors were held constant in accordance with SEC guidelines.
 
Economic Parameters
 
Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, lease operating expenses (LOE), workover expenses, overhead expenses and investments were calculated and prepared by you and were thoroughly reviewed by us for accuracy and completeness. LOE (column 22) was determined at the well level using averages determined from historical lease operating statements. All economic parameters, including expenses and investments, were held constant (not escalated) throughout the life of these properties.
 
Severance tax rates were applied at normal state percentages of oil and gas revenue. Ad valorem taxes were applied to each property as provided by your office.
 
Possible Effects of Federal and State Legislation
 
Federal, state and local laws and regulations, which are currently in effect and that govern the development and production of oil and natural gas, have been considered in the evaluation of proved reserves for this report. However, the impact of possible changes to legislation or regulations to future operating expenses and investment costs have not been included in the evaluation. These possible changes could have an effect on the reserves and economics. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.
 
SEC Conformance and Regulations
 
The reserve classifications and the economic considerations used herein for the SEC pricing scenario conform to the criteria of the SEC as defined in pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.


ANNEX B-2


Table of Contents

This evaluation includes 38 proved undeveloped locations based in various fields in Louisiana and New Mexico. Each of these drilling locations proposed as part of the Company’s development plan conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, the Company has indicated they have every intent to complete this development plan within the next five years. Furthermore, the Company has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five year development plan will be fully executed.


ANNEX B-3


Table of Contents

Reserve Estimation Methods
 
The methods employed in estimating reserves are described in page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.
 
Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for the Company properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.
 
General Discussion
 
The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.
 
An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included as part of the workover expenses described previously.
 
Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. This evaluation was supervised by Robert D. Ravnaas, Executive Vice President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #61304). We do not own an interest in the properties or Enduro Resource Partners LLC or Enduro Royalty Trust and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office. We consent to the filing of this report as an exhibit to the Annual Report on Form 10-K of Enduro Royalty Trust for the year end December 31, 2010.
 
Yours very truly,
 
 
Robert D. Ravnaas, P.E.
Executive Vice President
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Texas Registered Engineering Firm (F-693)


ANNEX B-4


Table of Contents

APPENDIX
Explanatory Comments for Summary Tables
 
HEADINGS
 
Table I
Description of Table Information
Identity of Interest Evaluated
Property Description — Location
Reserve Classification and Development Status
Effective Date of Evaluation
 
FORECAST
 
     
(Columns)
   
(1)(11)(21)
  Calendar or Fiscal years/months commencing on effective date.
(2)(3)(4)
  Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.
(5)(6)(7)
  Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage.
(8)
  Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
(9)
  Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
(10)
  Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.
(12)
  Revenue derived from oil sales — column (5) times column (8).
(13)
  Revenue derived from gas sales — column (6) times column (9).
(14)
  Revenue derived from NGL sales — column (7) times column (10).
(15)
  Revenue derived from hedge positions.
(16)
  Revenue not derived from column (12) through column (15); may include electrical sales revenue and saltwater disposal revenue.
(17)
  Total Revenue — sum of column (12) through column (16).
(18)
  Production-Severance taxes deducted from gross oil, gas and NGL revenue.
(19)
  Ad Valorem taxes.
(20)
  $/BOE6 — is the total of column (22), column (25), column (26), and column (27) divided by Barrels of Oil Equivalent (“BOE”). BOE is net oil production column (5) plus net gas production column (6) converted to oil at six Mcf gas per one bbl oil plus net NGL production column (7) converted to oil at one bbl NGL per 0.65 bbls of oil.
(22)
  Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS.
(23)
  Average gross wells.
(24)
  Average net wells are gross wells times working interest.
(25)
  Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
(26)
  3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
(27)
  Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.


ANNEX B-5


Table of Contents

     
(28)
  Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
(29)(30)
  Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered.
(31)
  Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.
 
MISCELLANEOUS
 
     
DCF Profile
 
•   The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns (30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile.
Life
 
•   The economic life of the appraised property is noted in the lower right-hand corner of the table.
Footnotes
 
•   Comments regarding the evaluation may be shown in the lower left-hand footnotes.
Price Deck
 
•   A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes.

ANNEX B-6


Table of Contents

APPENDIX
Methods Employed in the Estimation of Reserves
 
The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy.  Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.
 
Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.
 
A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:
 
Production performance.  This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as “decline curve” analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.
 
Material balance.  This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.
 
Volumetric.  This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.


ANNEX B-7


Table of Contents

Analogy.  This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.
 
Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.


ANNEX B-8


Table of Contents

APPENDIX
Reserve Definitions and Classifications
 
The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:
 
“(22) Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
 
“(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
 
“(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
 
“(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
 
“(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
 
“(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
 
“(6) Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
 
“(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
 
“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
“(31) Undeveloped oil and gas reserves.  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.


ANNEX B-9


Table of Contents

“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
 
“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
 
“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
 
“(18) Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
 
“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
 
“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
 
“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
 
“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).
 
“(17) Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
 
“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
 
“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
 
“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
 
“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
 
“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.


ANNEX B-10


Table of Contents

“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”
 
Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S — K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”
 
“(26) Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
 
“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”


ANNEX B-11


Table of Contents

 
Cawley, Gillespie & Associates, Inc.
 
PETROLEUM CONSULTANTS
 
         
9601 AMBERGLEN BLVD., SUITE 117 AUSTIN, TEXAS 78729-1106
512-249-7000
  306 WEST SEVENTH STREET, SUITE 302
FORT WORTH, TEXAS 76102-4987
817-336-2461
www.cgaus.com
  1000 LOUISIANA STREET, SUITE 625
HOUSTON, TEXAS 77002-5008
713-651-9944
 
May 10, 2011
 
Mr. John W. Arms
COO Executive Vice President
Enduro Resource Partners LLC
777 Main St., Suite 800
Fort Worth, TX 76102
 
Re: Pro Forma Evaluation
Enduro Royalty Trust Interests
Total Proved Reserves for Enduro Royalty Trust
 Net Profits Interest of the Underlying Properties
Texas, Louisiana and New Mexico Properties
Using Yearend SEC Prices as of December 31, 2010
 
Pursuant to the Guidelines of the Securities and
Exchange Commission for Reporting Corporate
Reserves and Future Net Revenue
 
Dear Mr. Arms:
 
As requested, this report was prepared on May 10, 2011 for Enduro Resource Partners LLC (“Company”) for the purpose of submitting our estimates of total proved reserves and forecasts of economics attributable to the Enduro Royalty Trust (“Trust”) net profits interests. We evaluated 100% of the Trust reserves, which are made up of oil and gas properties in Texas, Louisiana and New Mexico owned by the Company. This evaluation utilized an effective date of December 31, 2010, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (SEC). A composite summary of the proved reserves is presented below.
 
                                     
            Proved
       
        Proved
  Developed
       
        Developed
  Non-
  Proved
  Total
        Producing   Producing   Undeveloped   Proved
         
 
Net Reserves
                                   
Oil
  − Mbbl     5,352.0       0.0       190.0       5,541.8  
Gas
  − MMcf     26,153.6       1,554.0       15,314.9       43,058.0  
NGL
  − Mbbl     100.6       0.0       0.0       100.6  
Revenue
                                   
Oil
  − M$     408,630.2       0.0       14,384.5       423,014.7  
Gas
  − M$     119,425.4       6,309.4       62,638.7       188,373.4  
NGL
  − M$     4,702.8       0.0       0.0       4,702.8  
Severance Taxes
  − M$     29,593.6       160.4       3,168.4       32,922.4  
Ad Valorem Taxes
  − M$     14,049.6       123.0       1,799.6       15,972.2  
Operating Expenses
  − M$     0.0       0.0       0.0       0.0  
Investments
  − M$     0.0       0.0       0.0       0.0  
Net Operating Income (BFIT)
  − M$     489,115.2       6,026.0       72,055.1       567,196.3  
Discounted at 10%
  − M$     251,206.7       3,520.5       24,960.5       279,687.7  


ANNEX C-1


Table of Contents

Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.
 
The oil reserves include oil and condensate. Oil volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base.
 
Our estimates are for proved reserves only and do not include any probable or possible reserves nor have any values been attributed to interest in acreage beyond the location for which undeveloped reserves have been estimated.
 
Net Profits Calculations
 
The net profits interests entitle the Trust to receive 80% of the net proceeds attributable to the Company interest from the sale of production from the underlying properties.
 
Hydrocarbon Pricing
 
The base SEC oil and gas prices calculated for December 31, 2010 were $79.43/bbl and $4.37/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices (EIA) during 2010 and the base gas price is based upon Henry Hub spot prices (EIA) during 2010.
 
The base prices were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $76.34 per barrel for oil and $4.65 per MCF for gas. All economic factors were held constant in accordance with SEC guidelines.
 
Economic Parameters
 
Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, lease operating expenses (LOE), workover expenses, overhead expenses and investments were calculated and prepared by you and were thoroughly reviewed by us for accuracy and completeness. LOE (column 22) was determined at the well level using averages determined from historical lease operating statements. All economic parameters, including expenses and investments, were held constant (not escalated) throughout the life of these properties.
 
Severance tax rates were applied at normal state percentages of oil and gas revenue. Ad valorem taxes were applied to each property as provided by your office.
 
Possible Effects of Federal and State Legislation
 
Federal, state and local laws and regulations, which are currently in effect and that govern the development and production of oil and natural gas, have been considered in the evaluation of proved reserves for this report. However, the impact of possible changes to legislation or regulations to future operating expenses and investment costs have not been included in the evaluation. These possible changes could have an effect on the reserves and economics. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.
 
SEC Conformance and Regulations
 
The reserve classifications and the economic considerations used herein for the SEC pricing scenario conform to the criteria of the SEC as defined in pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.


ANNEX C-2


Table of Contents

This evaluation includes 38 proved undeveloped locations based in various fields in Louisiana and New Mexico. Each of these drilling locations proposed as part of the Company’s development plan conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, the Company has indicated they have every intent to complete this development plan within the next five years. Furthermore, the Company has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five year development plan will be fully executed.


ANNEX C-3


Table of Contents

Reserve Estimation Methods
 
The methods employed in estimating reserves are described in page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.
 
Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for the Company properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.
 
General Discussion
 
The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.
 
An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included as part of the workover expenses described previously.
 
Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. This evaluation was supervised by Robert D. Ravnaas, Executive Vice President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #61304). We do not own an interest in the properties or Enduro Resource Partners LLC or Enduro Royalty Trust and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office. We consent to the filing of this report as an exhibit to the Annual Report on Form 10-K of Enduro Royalty Trust for the year end December 31, 2010.
 
Yours very truly,
 
 
Robert D. Ravnaas, P.E.
Executive Vice President
Cawley, Gillespie & Associates, Inc.
Texas Registered Engineering Firm (F-693)


ANNEX C-4


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APPENDIX
Explanatory Comments for Summary Tables
 
HEADINGS
 
Table I
Description of Table Information
Identity of Interest Evaluated
Property Description — Location
Reserve Classification and Development Status
Effective Date of Evaluation
 
FORECAST
 
     
(Columns)
   
(1)(11)(21)
  Calendar or Fiscal years/months commencing on effective date.
(2)(3)(4)
  Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.
(5)(6)(7)
  Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage.
(8)
  Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
(9)
  Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
(10)
  Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.
(12)
  Revenue derived from oil sales — column (5) times column (8).
(13)
  Revenue derived from gas sales — column (6) times column (9).
(14)
  Revenue derived from NGL sales — column (7) times column (10).
(15)
  Revenue derived from hedge positions.
(16)
  Revenue not derived from column (12) through column (15); may include electrical sales revenue and saltwater disposal revenue.
(17)
  Total Revenue — sum of column (12) through column (16).
(18)
  Production-Severance taxes deducted from gross oil, gas and NGL revenue.
(19)
  Ad Valorem taxes.
(20)
  $/BOE6 — is the total of column (22), column (25), column (26), and column (27) divided by Barrels of Oil Equivalent (“BOE”). BOE is net oil production column (5) plus net gas production column (6) converted to oil at six Mcf gas per one bbl oil plus net NGL production column (7) converted to oil at one bbl NGL per 0.65 bbls of oil.
(22)
  Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS.
(23)
  Average gross wells.
(24)
  Average net wells are gross wells times working interest.
(25)
  Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
(26)
  3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
(27)
  Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.


ANNEX C-5


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(28)
  Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
(29)(30)
  Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered.
(31)
  Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.
 
MISCELLANEOUS
 
     
DCF Profile
 
•   The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns (30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile.
Life
 
•   The economic life of the appraised property is noted in the lower right-hand corner of the table.
Footnotes
 
•   Comments regarding the evaluation may be shown in the lower left-hand footnotes.
Price Deck
 
•   A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes.

ANNEX C-6


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APPENDIX
Methods Employed in the Estimation of Reserves
 
The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy.  Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.
 
Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.
 
A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:
 
Production performance.  This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as “decline curve” analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.
 
Material balance.  This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.
 
Volumetric.  This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.


ANNEX C-7


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Analogy.  This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.
 
Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.


ANNEX C-8


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APPENDIX
Reserve Definitions and Classifications
 
The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:
 
“(22) Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
 
“(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
 
“(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
 
“(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
 
“(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
 
“(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
 
“(6) Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
 
“(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
 
“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
“(31) Undeveloped oil and gas reserves.  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.


ANNEX C-9


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“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
 
“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
 
“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
 
“(18) Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
 
“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
 
“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
 
“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
 
“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).
 
“(17) Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
 
“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
 
“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
 
“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
 
“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
 
“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.


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“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”
 
Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S-K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”
 
“(26) Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
 
“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”


ANNEX C-11


Table of Contents

 
You should rely only on the information contained in this prospectus or in any free writing prospectus Enduro Sponsor and the trust may authorize to be delivered to you. Until          , 2011 (25 days after the date of this prospectus), federal securities laws may require all dealers that effect transactions in the trust units, whether or not participating in this offering, to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.
 
13,200,000 Trust Units
 
(ENDURO ROYALTY TRUST LOGO)
 
 
Prospectus
        , 2011
 
 
Barclays Capital
Citigroup
Goldman, Sachs & Co.
RBC Capital Markets
Wells Fargo Securities
 
 
J.P. Morgan
Baird
Morgan Keegan
Stifel Nicolaus Weisel
Wunderlich Securities


Table of Contents

PART II
 
INFORMATION NOT REQUIRED IN PROSPECTUS
 
Item 13.   Other Expenses of Issuance and Distribution.
 
Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing and the NYSE listing fee, the amounts set forth below are estimates.
 
         
Registration fee
  $ 45,823  
FINRA filing fee
    38,468  
NYSE listing fee
    175,000  
Printing and engraving expenses
    450,000  
Fees and expenses of legal counsel
    1,600,000  
Accounting fees and expenses
    1,100,000  
Transfer agent and registrar fees
    5,000  
Trustee fees and expenses
    275,000  
Miscellaneous
    309,709  
Total
  $ 4,000,000  
 
Item 14.   Indemnification of Directors and Officers.
 
The trust agreement provides that the trustee and its officers, agents and employees shall be indemnified from the assets of the trust against and from any and all liabilities, expenses, claims, damages or loss incurred by it individually or as trustee in the administration of the trust and the trust assets, including, without limitation, any liability, expenses, claims, damages or loss arising out of or in connection with any liability under environmental laws, or in the doing of any act done or performed or omission occurring on account of it being trustee or acting in such capacity, except such liability, expense, claims, damages or loss as to which it is liable under the trust agreement. In this regard, the trustee shall be liable only for its own fraud, gross negligence or willful misconduct and shall not be liable for any act or omission of any agent or employee unless the trustee has acted in bad faith or with gross negligence in the selection and retention of such agent or employee. The trustee is entitled to indemnification from the assets of the trust and shall have a lien on the assets of the trust to secure it for the foregoing indemnification.
 
Under Enduro Sponsor’s operating agreement and subject to specified limitations, no manager, member or officer of Enduro Sponsor will be liable for, and such manager, member or officer will be indemnified and held harmless by Enduro Sponsor against, any and all losses, liabilities and reasonable expenses, including attorneys’ fees, arising from proceedings in which such manager, member or officer may be involved by reason of its being a manager, member or officer. Subject to any terms, conditions or restrictions set forth in Enduro Sponsor’s operating agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against all claims and demands whatsoever. Reference is made to the Underwriting Agreement to be filed as an exhibit to this registration statement, which provides for the indemnification of Enduro Sponsor, its managers and officers and any person who controls Enduro Sponsor, including indemnification for liabilities under the Securities Act.
 
In connection with the preparation and filing of any registration statement pursuant to the registration rights agreement, Enduro Sponsor will indemnify the trust and its agents from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or prospectus. Enduro Sponsor will bear all costs and expenses incidental to any registration statement, excluding any underwriting discounts and fees.


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Item 15   Recent Sales of Unregistered Securities.
 
In connection with the formation of the trust, the trust will issue to Enduro Sponsor trust units in exchange for the conveyance of the Net Profits Interest in an offering exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years by the trust.
 
Item 16.   Exhibits and Financial Statement Schedules.
 
(a) Exhibits.
 
The following documents are filed as exhibits to this registration statement:
 
             
Exhibit
       
Number
     
Description
 
  1 .1**     Form of Underwriting Agreement.
  3 .1†     Certificate of Formation of Enduro Resource Partners LLC.
  3 .2†     Amended & Restated Operating Agreement of Enduro Resource Partners LLC.
  3 .3†     Certificate of Trust of Enduro Royalty Trust.
  3 .4†     Trust Agreement.
  3 .5†     Form of Amended and Restated Trust Agreement.
  5 .1*     Opinion of Richards, Layton & Finger, P.A. relating to the validity of the trust units.
  8 .1*     Opinion of Latham & Watkins LLP relating to tax matters.
  10 .1†     Form of Net Profits Interest Conveyance.
  10 .2†     Form of Registration Rights Agreement.
  21 .1†     Subsidiaries of Enduro Resource Partners LLC.
  23 .1*     Consent of Ernst & Young, LLP — Fort Worth, Texas office.
  23 .2*     Consent of Ernst & Young, LLP — Tulsa, Oklahoma office.
  23 .3*     Consent of Richards, Layton & Finger, P.A. (contained in Exhibit 5.1).
  23 .4*     Consent of Latham & Watkins LLP (contained in Exhibit 8.1).
  23 .5*     Consent of Cawley, Gillespie & Associates, Inc.
  24 .1†     Powers of Attorney (included on the signature pages).
  99 .1*     Summary Reserve Reports of Cawley, Gillespie & Associates, Inc. (included as Annexes A-1, A-2, A-3, B and C to the prospectus).
 
 
 † Previously filed.
 
 * Filed herewith.
 
 ** To be filed by amendment.
 
(b) Financial Statement Schedules.
 
No financial statement schedules are required to be included herewith or they have been omitted because the information required to be set forth therein is not applicable.
 
Item 17.   Undertakings.
 
The undersigned registrants hereby undertake:
 
(a) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrants pursuant to the provisions described in Item 14, or otherwise, the registrants have been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrants of


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expenses incurred or paid by a director, officer or controlling person of the registrants in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrants will, unless in the opinion of their respective counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by them is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.
 
(b) To provide to the underwriters at the closing specified in the underwriting agreement, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
 
(c) For purpose of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in the form of prospectus filed by the registrants pursuant to Rule 424(b) (1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.
 
(d) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
 
(e) To send to each trust unitholder at least on an annual basis a detailed statement of any transactions with the trustees or their respective affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to the trustees or their respective affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.
 
(f) To provide to the trust unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the trust.


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SIGNATURES
 
Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Fort Worth, State of Texas, on July 29, 2011.
 
Enduro Resource Partners LLC
 
  By: 
/s/  Jon S. Brumley
Jon S. Brumley
President and Chief Executive Officer
 
Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed by the following persons on July 29, 2011 in the capacities indicated.
 
         
Signature
 
Title
 
     
/s/  Jon S. Brumley

Jon S. Brumley
  President, Chief Executive Officer and Manager
(Principal Executive Officer)
     
/s/  Kimberly A. Weimer

Kimberly A. Weimer
  Vice President, Chief Financial Officer
(Principal Financial and Accounting Officer)
     
/s/  John W. Arms

John W. Arms
  Manager
     
*

David Leuschen
  Manager
     
*

Pierre F. Lapeyre, Jr.
  Manager
     
*

N. John Lancaster
  Manager
     
*

I. Jon Brumley
  Manager
         
*By:  
/s/  Jon S. Brumley

Jon S. Brumley
Attorney-in-Fact
   


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SIGNATURES
 
Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Fort Worth, State of Texas, on July 29, 2011.
 
Enduro Royalty Trust
 
By: Enduro Resource Partners LLC
 
  By: 
/s/  Jon S. Brumley
Jon S. Brumley
President and Chief Executive Officer


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INDEX TO EXHIBITS
 
             
Exhibit
       
Number
     
Description
 
  1 .1**     Form of Underwriting Agreement.
  3 .1†     Certificate of Formation of Enduro Resource Partners LLC.
  3 .2†     Amended & Restated Operating Agreement of Enduro Resource Partners LLC.
  3 .3†     Certificate of Trust of Enduro Royalty Trust.
  3 .4†     Trust Agreement.
  3 .5†     Form of Amended and Restated Trust Agreement.
  5 .1*     Opinion of Richards, Layton & Finger, P.A. relating to the validity of the trust units.
  8 .1*     Opinion of Latham & Watkins LLP relating to tax matters.
  10 .1†     Form of Net Profits Interest Conveyance.
  10 .2†     Form of Registration Rights Agreement.
  21 .1†     Subsidiaries of Enduro Resource Partners LLC.
  23 .1*     Consent of Ernst & Young, LLP — Fort Worth, Texas office.
  23 .2*     Consent of Ernst & Young, LLP — Tulsa, Oklahoma office.
  23 .3*     Consent of Richards, Layton & Finger, P.A. (contained in Exhibit 5.1).
  23 .4*     Consent of Latham & Watkins LLP (contained in Exhibit 8.1).
  23 .5*     Consent of Cawley, Gillespie & Associates, Inc.
  24 .1†     Powers of Attorney (included on the signature pages).
  99 .1*     Summary Reserve Reports of Cawley, Gillespie & Associates, Inc. (included as Annexes A-1, A-2, A-3, B and C to the prospectus).
 
 
†  Previously filed.
 
Filed herewith.
 
**  To be filed by amendment.