##### Table of Contents





As filed with the
    Securities and Exchange Commission on July 1,
    2011
 
 
 Registration
    No. 333-174225
 
     UNITED STATES SECURITIES AND
    EXCHANGE COMMISSIONWashington, D.C.
    20549
    
    Amendment No. 1
    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:
     o
  o
  o
  o
  Rule 12b-2
 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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##### Table of Contents



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 1, 2011
 
  PROSPECTUS
   
  [     ]
    Trust Units
 
  
   
   
 
   
    The trust units.
 
  The trust.
 
 
  The trust unitholders.
 
 
  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

TotalPrice to the public

$



$Underwriting discounts and
    commissions(1)

$



$Proceeds, before expenses, to Enduro Sponsor

$



$    
  (1)

    
    Excludes a structuring fee of [     ]%
    of the gross proceeds of the offering payable to Barclays
    Capital Inc. by Enduro Sponsor for the evaluation, analysis and
    structuring of the trust. 
 
   
       
   Barclays
    Capital
    Citi
    Goldman, Sachs & Co.
    RBC Capital Markets
    Wells
    Fargo Securities




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##### 



TABLE OF
    CONTENTS
   
 
 PROSPECTUS SUMMARY

1RISK FACTORS

17FORWARD-LOOKING STATEMENTS

34USE OF PROCEEDS

35ENDURO SPONSOR

36CERTAIN RELATIONSHIPS AND RELATED PARTY
    TRANSACTIONS

42THE TRUST

43PROJECTED CASH DISTRIBUTIONS

44THE UNDERLYING PROPERTIES

51COMPUTATION OF NET PROFITS

77DESCRIPTION OF THE TRUST AGREEMENT

81DESCRIPTION OF THE TRUST UNITS

86TRUST UNITS ELIGIBLE FOR FUTURE SALE

89FEDERAL INCOME TAX CONSEQUENCES

91STATE TAX CONSIDERATIONS

98ERISA CONSIDERATIONS

99SELLING TRUST UNITHOLDER

100UNDERWRITING (CONFLICTS OF INTEREST)

101LEGAL MATTERS

106EXPERTS

106WHERE YOU CAN FIND MORE INFORMATION

106GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

107INDEX TO FINANCIAL STATEMENTS

F-1INFORMATION ABOUT ENDURO RESOURCE PARTNERS LLC
    (ENDURO SPONSOR)

ENDURO-1INDEX TO FINANCIAL STATEMENTS OF ENDURO
    SPONSOR

ENDURO F-1SUMMARY OF RESERVE REPORT OF PREDECESSOR
    PROPERTIES

ANNEX A-1-1SUMMARY OF RESERVE REPORT OF SAMSON PERMIAN BASIN
    ASSETS

ANNEX A-2-1SUMMARY OF RESERVE REPORT OF CONOCOPHILLIPS
    PERMIAN BASIN ASSETS

ANNEX A-3-1SUMMARY OF RESERVE REPORT OF THE UNDERLYING
    PROPERTIES

ANNEX B-1SUMMARY OF RESERVE REPORT OF ENDURO ROYALTY
    TRUST

ANNEX C-1EX-23.1EX-23.2EX-23.5  
   Important Notice
    About Information in This Prospectus




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##### Table of Contents



PROSPECTUS
    SUMMARY
  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
 1




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##### Table of Contents



Underlying PropertiesAverage Daily NetAs of December 31, 2010


Production For YearProved
    Reserves(1)


Ended December 31,


As of December 31,PV-10


Total





% Proved Developed


2010


2010Operating 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



13East Texas/North Louisiana


69,557



10,743



0
%


48
%


2,321



13Total

$
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.
 2




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##### Table of Contents



operator(s) PV-10
 
  % of TotalPV-10 at


PV-10 atField Name

Operator

December 31, 2010


December 31, 2010(In thousands)Elm Grove Field

Petrohawk Energy Corporation, 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
%   Key Investment
    Considerations
   
  
    Stable oil base combined with significant production and
    inventories of low risk natural gas locations. The
    Underlying Properties in the Permian Basin region include
    multiple mature oil fields currently using secondary and
    tertiary recovery methods. These fields typically are
    characterized by stable 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
 3




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
    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 91% 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 for well established production profiles and increased
    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 70%, 76% and 67% of expected oil and natural gas
    production for 2011, 2012 and 2013, respectively, from the
    proved developed 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 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%.
 4




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
    Aligned interests of sponsor.  Immediately
    following the closing of this offering, Enduro Sponsor will have
    an effective ownership of approximately
    [     ]% 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
    [     ]% of the trust units. 
  Formation
    Transactions
   
  
    Enduro Sponsor will convey to the trust the Net Profits Interest
    effective as of May 1, 2011 in exchange for
    [          ]
    trust units in the aggregate, representing all of the
    outstanding trust units of the trust. 
 
  
    Enduro Sponsor will sell
    [          ]
    trust units offered hereby, representing an
    [     ]% interest in the trust. Enduro
    Sponsor will also make available during the
    30-day
    option period up to
    [          ]
    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
 
    
  Risk
    Factors
 
   
 
  
    Prices of oil and natural gas fluctuate, and lower prices could
    reduce proceeds to the trust and cash distributions to trust
    unitholders. 
 
  
    Estimates of future cash distributions to trust unitholders are
    based on assumptions that are inherently subjective.
 5




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
    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.
    The trading price for the trust units may not reflect the value
    of the Net Profits Interest held by the trust.
 6




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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. 
  
    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, 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.
 7




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
    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
 
   
  
 Three Months Ended


Year EndedMarch 31, 2011


December 31, 2010(In thousands)(Unaudited)Revenues:Oil

$
20,150


$
70,033Natural gas


7,262



33,787Total revenues

$
27,412


$
103,820Direct operating expenses:Lease operating

$
6,185


$
24,579Gathering and processing


489



1,977Production and other taxes


2,005



8,069Total direct operating expenses

$
8,679


$
34,625Excess of revenues over direct operating expenses

$
18,733


$
69,195  
  Unaudited Pro
    Forma Distributable Income of the Trust
 8




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##### Table of Contents



Three Months Ended


Year EndedMarch 31, 2011


December 31, 2010(In thousands, except per unit data)(Unaudited)Excess of revenues over direct operating expenses

$
18,733


$
69,195Less development expenses


12,105



37,036Excess of revenues over direct operating expenses and
    development expenses

$
6,628


$
32,159Times Net Profits Interest


80
%


80
%Income from Net Profits Interest

$
5,302


$
25,727Pro forma adjustments:Less estimated trust general and administrative expenses

$
213


$
850Distributable income

$
5,089


$
24,877Distributable income per trust unit

$
[     ]


$
[     ]  
  Pro Forma
    Combined Operating Data of the Underlying
    Properties
 
   
  
 Three Months EndedMarch 31,


Year Ended December 31,2011


2010


2010


2009


2008(Unaudited)Operating Data:Sales volumes:Oil (MBbls)


230



239



939



1,016



1,084Natural gas (MMcf)


1,619



1,768



7,171



8,455



8,868Total sales (MBoe)


500



534



2,134



2,425



2,562Average sales prices:Oil (per Bbl)

$
87.61


$
72.61


$
74.58


$
54.44


$
98.52Natural gas (per Mcf)


4.49



5.56



4.71



3.91



8.57Average costs per Boe:Lease operating

$
12.37


$
11.62


$
11.52


$
10.65


$
11.45Gathering and processing


0.98



0.79



0.93



0.78



1.18Production and other taxes


4.01



3.58



3.78



3.10



4.38Capital expenditures (in thousands):Property development costs

$
12,105


$
1,781


$
37,036


$
18,532


$
65,571
 9




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##### Table of Contents



Summary
    Historical and Unaudited Pro Forma Financial Data of Enduro
    Sponsor
 
  (i) Predecessor-EAC (ii) Predecessor-DNR
 
 
   
 
   
  
 EnduroSponsor



EnduroEnduro

Pro Forma



SponsorSponsor

as Adjusted



Pro FormaPro Forma

for the Offering

Enduro

as Adjustedfor the

(Including the

Sponsor

for the OfferingAcquisition

Conveyance of

Pro Forma for the

(including theof the

Net Profits

Acquisition of the

Conveyance of the

Enduro Sponsor


Enduro Sponsor


Predecessor-DNR


Predecessor-EACAcquired Properties

Interest)

Acquired Properties

Net Profits Interest)

Three Months

Inception


Inception


March 9, 2010


January 1,Three Months Ended

Three Months Ended

Year Ended

Year Ended

Ended

Through


Through


Through


2010March 31,

March 31,

December 31,

December 31,

March 31,

March 31,


December 31,


November 30,


Through2011

2011

2010

2010

2011

2010


2010


2010


March 8, 2010(In thousands)

(Unaudited)

(Unaudited)

(Unaudited)

(Unaudited)

(Unaudited)

(Unaudited)Revenues

$
33,793


$
31,142


$
137,712


$
124,848


$
22,952


$




$
3,975



$
40,210



$
12,164Net income (loss)

$
(9,559
)

$
(5,847
)

$
(8,645
)

$
6,185


$
(11,495
)

$
(77
)


$
(8,222
)


$
(19,515
)


$
(17,821
)Total assets (at period end)





$
610,335










$
735,806


$
100



$
361,832



$
397,314



$
313,106Long-term liabilities, excluding current maturities (at period
    end)





$
27,392










$
260,392


$




$
66,211



$
587



$
1,412Members equity/owners equity





$
552,672










$
445,143


$
23



$
273,939



$
374,731



$
290,073  
  Summary Projected
    Cash Distributions
 10




---



##### Table of Contents



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.
 
      
    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 April 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 $7.2 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.
 11




---



##### Table of Contents



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.
 12




---



##### Table of Contents



Projections for the TwelveMonth Period EndingProjected Cash Distributions to Trust Unitholders

September 30, 2012(In thousands,except per unit data)Underlying Properties sales volumes:Oil
    (MBbl)(1)


911Natural gas (MMcf)


7,119Total sales (MBoe)


2,097Assumed NYMEX
    price(2):Oil (per Bbl)

$
100.00Natural gas (per MMBtu)


4.50Assumed realized sales
    price(3):Oil (per Bbl)

$
96.54Natural gas (per Mcf)


4.63Calculation of net profits:Gross
    profits(4):Oil sales

$
87,940Natural gas sales


32,979Total


120,919Costs:Direct operating expenses:Lease operating expenses

$
23,489Production and other taxes


9,225Development
    expenses(5)


14,000Total


46,714Settlement of hedge
    contracts(6)


830Net adjustment for additional
    projects(7)


(989
)Net profits


74,046Percentage allocable to Net Profits Interest


80%Net profits to trust from Net Profits Interest

$
59,237Trust general and administrative
    expenses(8)


850Cash available for distribution by the trust

$
58,387Cash distribution per trust unit (assumes
    [     ] units)

$
[     ]  
    (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. 
  (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.
 13




---



##### Table of Contents



(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
    $9.0 million (or $7.2 million attributable to the
    trusts Net Profits Interest) of the total estimated
    development expenses of $11.9 million related to the
    21 gross (2.4 net) wells, thereby reducing the
    trusts share of development expenses associated with these
    wells to $2.3 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
    $7.2 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. 
  Enduro
    Sponsor
     
   
  (817) 744-8200.
 14




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##### Table of Contents



The
    Offering
 
  Trust units offered by Enduro Sponsor
    
    [          ]
    trust units, or
    [          ]
    trust units if the underwriters exercise their option to
    purchase additional trust units in full 
 
  Trust units owned by Enduro Sponsor after the offering
    
    [          ]
    trust units, or
    [          ]
    trust units if the underwriters exercise their option to
    purchase additional trust units in full 
 
  Trust units outstanding after the offering
    
    [          ]
    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 amounts outstanding under its senior
    secured credit agreement and for general limited liability
    company purposes, which may include additional acquisitions.
    Enduro Sponsor is deemed to be an underwriter with respect to
    the trust units offered hereby. Please read Use of
    Proceeds. 
  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 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
 15




---



##### Table of Contents



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, 20[ ],
    will recognize, on a cumulative basis, an amount of federal
    taxable income for that period of approximately
    [     ]% 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.
 16




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##### Table of Contents



RISK
    FACTORS  Prices of oil
    and natural gas fluctuate, and lower prices could reduce
    proceeds to the trust and cash distributions to trust
    unitholders.
 
  month-to-month
  
    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.   
   
 
   
 
   
 17




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##### Table of Contents



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.
 
   
 18




---



##### Table of Contents




    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.   
  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.
 
 
   
 
  
    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. 
   
 
  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.
 
   19




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##### Table of Contents




    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. 
   
  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.
 
   
 20




---



##### Table of Contents



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.
 
   
  12-month
 21




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##### Table of Contents



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.
 
 
   
 
   
   
   
 22




---



##### Table of Contents



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.
 
   23




---



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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.
 
   
  The trading
    price for the trust units may not reflect the value of the Net
    Profits Interest held by the trust.
 
   
 24




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##### Table of Contents



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.
    
    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.
 
 
   
  Trust
    unitholders have limited ability to enforce provisions of the
    Net Profits Interest, and Enduro Sponsors liability to the
    trust is limited.
   25




---



##### Table of Contents



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.
 
 
   
   26




---



##### Table of Contents



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.
 
 
   
     27




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##### Table of Contents



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.
 
  case-by-case
 
 
  and/or
 
 28




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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.
 
   
 29




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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.
 
 
   
 30




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##### Table of Contents



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.
    Tax Risks Related
    to the Trusts 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.
   31




---



##### Table of Contents



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.
 
   
      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.
   32




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##### Table of Contents



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.
 
   
 33




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##### Table of Contents



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.   
   
 34




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##### Table of Contents



USE OF
    PROCEEDS   
 
   
 
 
  
 Intended AmountIntended Use

Dedicated to Such UseRepay borrowings outstanding under senior secured credit
    agreement

$
millionGeneral limited liability company purposes

$
million  
   
   
 35




---



##### Table of Contents



ENDURO
    SPONSOR   
 
   
  The trust units do not represent interests in, or obligations
    of, Enduro Sponsor.
 36




---



##### Table of Contents



Summary
    Historical and Unaudited Pro Forma Financial, Operating and
    Reserve Data of Enduro Sponsor
 
   
 
   
 
   
  
 EnduroSponsor





EnduroEnduro


Pro Forma as


Enduro


SponsorSponsor


Adjusted for


Sponsor


Pro Forma asPro Forma


the Offering


Pro Forma


Adjusted forfor the


(Including the


for the


the OfferingAcquisition


Conveyance


Acquisition


(Including theof the


of the


of the


ConveyanceAcquired


Net Profits


Acquired


of the


Enduro Sponsor



Enduro Sponsor







Predecessor-EACProperties


Interest)


Properties


Net Profits Interest)













Predecessor-DNR



January 1,Three Months


Three Months


Year


Year


Three Months


Inception



Inception



March 9, 2010



2010Ended


Ended


Ended


Ended


Ended


Through



Through



Through



ThroughMarch 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


$
31,142


$
137,712


$
124,848


$
22,952


$




$
3,975



$
40,210



$
12,164


$
33,907


$
62,370Net income (loss)

$
(9,559
)

$
(5,847
)

$
(8,645
)

$
6,185


$
(11,495
)

$
(77
)


$
(8,222
)


$
(19,515
)


$
(17,821
)

$
(25,853
)

$
19,540Total assets (at period end)





$
610,335










$
735,806


$
100



$
361,832



$
397,314



$
313,106


$
301,127


$
256,783Long-term liabilities, excluding current maturities (at
    period end)





$
27,392










$
260,392


$




$
66,211



$
587



$
1,412


$
1,404


$
1,322Members equity/owners equity





$
552,672










$
445,143


$
23



$
273,939



$
374,731



$
290,073


$
281,439


$
234,433  
 37




---



##### Table of Contents



Enduro Sponsor


Predecessor-DNR


Predecessor - EACInception


Inception


March 9, 2010


January 1Through


Through


Through


Through

Year EndedMarch 31,


December 31,


November 30,


March 8,

December 31,2010


2010


2010


2010

2009

2008Production (MBoe)








143




1,505




329



1,463



1,194Net proved reserves (MBoe) (at period end)








16,432




18,059




17,936



18,265



10,357Net proved developed reserves (MBoe) (at period end)








10,667




9,679




8,685



9,014



7,836  
 
  Management of
    Enduro Sponsor
 
 
   
  
 Name

Age

TitleJon S. Brumley

40

President, Chief Executive Officer and ManagerJohn W. Arms

44

Executive Vice President, Chief Operating Officer and ManagerKimberly A. Weimer

32

Vice President and Chief Financial OfficerBill R. Pardue

38

Director, Engineering and OperationsDavid J. Grahek

57

Director, GeologyDavid Leuschen

60

ManagerPierre F. Lapeyre, Jr.

48

ManagerN. John Lancaster

43

ManagerI. Jon Brumley

72

Manager  
 
  Jon S. Brumley
 
 
  John W. Arms
 
 38




---



##### Table of Contents



Kimberly A. Weimer
 
 
  Bill R. Pardue
 
 
  David J. Grahek
 
 
  David Leuschen
 
 
  Pierre F. Lapeyre, Jr. 14-year
 
 39




---



##### Table of Contents



N. John Lancaster
 
 
  I. Jon Brumley
 
 40




---



##### Table of Contents



Beneficial
    Ownership of Enduro Sponsor
 
   
  
    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. 
    
 Percentage ofMembershipInterestsBeneficiallyName of Beneficial Owner

OwnedEnduro Resource Holdings LLC


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)


  
 
 
  Beneficial
    Ownership of Enduro Royalty Trust
    
 Class of

Percentage ofName of Beneficial Owner

Securities

OwnershipEnduro Sponsor

Trust Units


[     ]
%  
 41




---



##### Table of Contents



CERTAIN
    RELATIONSHIPS AND RELATED PARTY TRANSACTIONS   
 42




---



##### Table of Contents



THE
    TRUST   
   
  out-of-pocket
 
   43




---



##### Table of Contents



PROJECTED CASH
    DISTRIBUTIONS      
    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. 
   
 
  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.
 
      
    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 April 30, 2012; 
 44




---



##### Table of Contents




    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 $7.2 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. 
 
   
 
  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.
 
   
   
 45




---



##### Table of Contents



Projections for theTwelve Month PeriodEnding September 30,Projected Cash Distributions to Trust Unitholders

2012(In thousands, except per unit data)Underlying Properties sales volumes:Oil
    (MBbl)(1)


911Natural gas (MMcf)


7,119Total sales (MBoe)


2,097Assumed NYMEX
    price(2):Oil (per Bbl)

$
100.00Natural gas (per MMBtu)


4.50Assumed realized sales
    price(3):Oil (per Bbl)

$
96.54Natural gas (per Mcf)


4.63Calculation of net profits:Gross
    profits(4):Oil sales

$
87,940Natural gas sales


32,979Total

$
120,919Costs:Direct operating expenses:Lease operating expenses

$
23,489Production and other taxes


9,225Development
    expenses(5)


14,000Total

$
46,714Settlement of hedge
    contracts(6)


830Net adjustment for additional
    projects(7)


(989
)Net profits

$
74,046Percentage allocable to Net Profits Interest


80%Net profits to trust from Net Profits Interest

$
59,237Trust general and administrative
    expenses(8)

$
850Cash available for distribution by the trust

$
58,387Cash distribution per trust unit (assumes
    [     ] million units)

$
[       ]  
    (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. 
 46




---



##### Table of Contents



(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
    $9.0 million (or $7.2 million attributable to the
    trusts Net Profits Interest) of the total estimated
    development expenses of $11.9 million related to the
    21 gross (2.4 net) wells, thereby reducing the
    trusts share of development expenses associated with these
    wells to $2.3 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
    $7.2 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. th th
 
 
  Production estimates and development
    expenses.
 
 47




---



##### Table of Contents



Oil and natural gas prices.
 
 
   
      Settlement of Hedge Contracts.
  Costs.
 
  Net adjustment for additional projects.
 
 48




---



##### Table of Contents



General and administrative expense. out-of-pocket
 
  Sensitivity of
    Projected Cash Distributions to Oil and Natural Gas Production
    and Prices
   
   
 49




---



##### Table of Contents



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.
 
   
  Sensitivity of
    Projected Annual Cash Distribution Per Trust Unit
    to Changes in NYMEX Futures Pricing
  
 50




---



##### Table of Contents



THE UNDERLYING
    PROPERTIES   
 
  PV-10 PV-10
 
    
 80% of the


NetUnderlying


Underlying


ProfitsProperties(1)


Properties(2)


Interest(In thousands)Proved ReservesOil
    (MBbls)(3)


12,766



10,213



5,642Natural Gas (MMcf)


85,787



68,630



43,058Oil Equivalents
    (Mboe)(4)


27,064



21,651



12,818Future Net Revenues

$
1,344,718


$
1,075,774


$
616,091Future Production Cost

$
578,014


$
462,411


$
48,895
(5)Future Development Cost

$
57,674


$
46,139


$
Future Net Income

$
709,030


$
567,196


$
567,196Present Value at 10% Discount
    Rate(6)

$
349,532


$
279,688


$
279,688Standardized 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.(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. 51




---



##### Table of Contents



(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. 
 
   
    Unaudited Pro
    Forma Combined Financial and Operating Data of the Underlying
    Properties
 
   
  
 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


$
106,801Natural gas


7,262



9,838



33,787



33,053



76,001Total revenues

$
27,412


$
27,192


$
103,820


$
88,362


$
182,802Direct operating expenses:Lease operating

$
6,185


$
6,206


$
24,579


$
25,822


$
29,331Gathering and processing


489



419



1,977



1,885



3,035Production and other taxes


2,005



2,052



8,069



7,512



11,217Total direct operating expenses

$
8,679


$
8,677


$
34,625


$
35,219


$
43,583Excess of revenues over direct operating expenses

$
18,733


$
18,515


$
69,195


$
53,143


$
139,219  
 52




---



##### Table of Contents



Three Months EndedMarch 31,


Year Ended December 312011


2010


2010


2009


2008(Unaudited)Operating data:Sales volumes:Oil (MBbls)


230



239



939



1,016



1,084Natural gas (MMcf)


1,619



1,768



7,171



8,455



8,868Total sales (MBoe)


500



534



2,134



2,425



2,562Average sales prices:Oil (per Bbl)

$
87.61


$
72.61


$
74.58


$
54.44


$
98.52Natural gas (per Mcf)


4.49



5.56



4.71



3.91



8.57Average costs per Boe:Lease operating

$
12.37


$
11.62


$
11.52


$
10.65


$
11.45Gathering and processing


0.98



0.79



0.93



0.78



1.18Production and other taxes


4.01



3.58



3.78



3.10



4.38Capital expenditures (in thousands):Property development costs

$
12,105


$
1,781


$
37,036


$
18,532


$
65,571  
  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
 
 
   
 
  Revenues.
 
 
  Lease operating expenses.
 
 
  Gathering and processing expenses.
 
 
  Production and other taxes.
 
  Comparison of
    Pro Forma Combined Historical Results for the Years Ended
    December 31, 2010 and 2009
   53




---



##### Table of Contents



Revenues.
 
  Lease operating expenses.
 
  Gathering and processing expenses.
  Production and other taxes.
  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 unaudited
    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.
 
    Revenues.
  Lease operating expenses.
 
  Gathering and processing expenses.
 
  Production and other taxes.
  Hedge
    Contracts
   54




---



##### Table of Contents



Daily Put


Average


Daily Swap


AveragePeriod

Volumes


Price


Volumes


Price(Mcf)


($/Mcf)


(Mcf)


($/Mcf)April 2011  December 2011


14,000


$
4.20



10,000


$
4.30January 2012  December 2012


14,000


$
4.90



10,000


$
4.57January 2013  December 2013


12,000


$
4.90



8,000


$
5.00  
 
   
  
 Daily


Average





Average


Average


Average


DailyPut


Put


Daily


Sub-Floor


Floor


Cap


Swap


AverageVolumes


Price


Volumes


Price


Price


Price


Volumes


PricePeriod

(Bbls)


($/Bbl)


(Bbls)


($/Bbl)


($/Bbl)


($/Bbl)


(Bbls)


($/Bbl)2011


500


$
92.00



500


$
67.50


$
90.00


$
110.00



530


$
102.962012


500


$
92.00



500


$
67.50


$
90.00


$
110.00



520


$
104.102013





$




500


$
67.50


$
90.00


$
110.00



510


$
102.97  
    Producing Acreage
    and Well Counts
 
   
  AcresGross


NetPermian Basin


278,612



30,350East Texas/North Louisiana


15,440



4,113Total


294,052



34,463  55




---



##### Table of Contents



Oil


Natural GasGross
    Wells(1)


Net Wells


Gross
    Wells(1)


Net WellsPermian Basin


4,161



753.5



130



23.5East Texas/North Louisiana










385



100.7Total


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.    
 Year Ended December 31,2010


2009


2008Gross


Net


Gross


Net


Gross


NetDevelopment Wells:Productive


39



6.2



20



1.3



116



24.3Dry holes






















39



6.2



20



1.3



116



24.3Exploratory Wells:Productive


13



4.7



23



7.6



22



7.3Dry holes










3



0.6







13



4.7



26



8.2



22



7.3Total:Productive


52



10.9



43



8.9



138



31.6Dry holes










3



0.6







Total


52



10.9



46



9.5



138



31.6  
  Operating
    Areas
  PV-10
  
 Proved
    Reserves(1)% ofNatural





% of


PV-10


TotalProducing

Oil


Gas


Total


Total


Value(2)


PV-10Operating Area

Formation

(MBbls)


(MMcf)


(MBoe)


Reserves


(In thousands)


ValuePermian BasinNorth MonumentGrayburg 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
% 
 56




---



##### Table of Contents



Proved
    Reserves(1)% ofNatural





% of


PV-10


TotalProducing

Oil


Gas


Total


Total


Value(2)


PV-10Operating Area

Formation

(MBbls)


(MMcf)


(MBoe)


Reserves


(In thousands)


ValueEast Texas/North LouisianaElm 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 LouisianaTotal




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.    Oil Recovery
    Overview
 
   
   57




---



##### Table of Contents



2 2 2 2 2 2
  Permian Basin
    Region
  2
  PV-10
 
  
    The largest field in the Permian Basin region is the Apache
    operated North Monument Grayburg Unit discovered in 1929. This
    unit produces 325 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 365 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. 
 
  
    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 490 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 produced 165 Boe per day net to
    Enduro Sponsors interest of which 100% is oil. Proved
    reserves 
 58




---



##### Table of Contents



attributable to the Underlying Properties in the Yates Field
    are 633 MBoe as of December 31, 2010. 
 
   
  OriginalOil in

CumulativeRecovery

Working

Net Revenue

Place

Production

PV-10Unit Name

Operator

Method

Interest (%)

Interest (%)

(MMBO)(1)

(MMBO)

(Millions)North Monument Grayburg Unit

Apache

Waterflood


11.2



9.9



580
(2)


152


$
43North Central Levelland Unit

Apache

Waterflood


30.9



23.3



142
(3)


56


$
39North Cowden Unit

Occidental

Waterflood/CO2


8.5



7.6



1,266
(4)


270


$
33Yates Field Unit

Kinder Morgan

Waterflood/CO2


0.8



0.7



4,000
(5)


1,235


$
18South Foster Unit

Occidental

Waterflood


12.7



11.1



163
(6)


45


$
10Eunice Monument South Unit A

XTO

Waterflood


9.4



8.1



672
(7)


110


$
7Jo-Mill Unit

Chevron

Waterflood


1.2



1.1



326
(8)


76


$
4West Spraberry Unit

Chevron

Waterflood


22.7



19.7



60
(9)


14


$
4Spraberry Driver Unit

Pioneer

Waterflood


1.0



0.8



600
(10)


88


$
3Eunice Monument South Unit B

XTO

Waterflood


14.1



11.7



136
(11)


22


$
3Corrigan 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.(12)

    
    Texas Railroad Commission June 4, 1990
    Form H-1
    filing by ARCO Oil and Gas Company as operator.  2 2
 59




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##### Table of Contents



East Texas/North
    Louisiana Region
 
  - 80-acre 160-acre
 
 
  80-acre 80-acre 80-acre
 
  Near Term
    Development Activities
 
  Payment of
    Operating and Development Expenses
 
 
   
 
  2011 Capital
    Budget
 
 
  Historical Activity.
 
 60




---



##### Table of Contents



East Texas/North Louisiana Region.
 
 
   
 
   
 
 
 
  Permian Basin Region.
 
 
   
 
 
 
  2012 Capital
    Budget
 
 
   
 61




---



##### Table of Contents



80-acre
 
 
  2 2 2
 
 
  Other
 
    Reserve
    Reports
  Technologies.
 
   
 
  Internal controls.
 
 62




---



##### Table of Contents



first-day-of-the-month first-day-of-the-month
 63




---



##### Table of Contents



Proved reserves of Underlying Properties.
  
 80% of theUnderlying


Underlying


Net ProfitProperties(1)


Properties(2)


Interests(In thousands)Proved ReservesOil
    (MBbls)(3)


12,766



10,213



5,642Natural Gas (MMcf)


85,787



68,630



43,058Oil Equivalents
    (Mboe)(4)


27,064



21,651



12,818Future Net Revenue

$
1,344,718


$
1,075,774


$
616,091Future Production Cost

$
578,014


$
462,411


$
48,895
(5)Future Development Cost

$
57,674


$
46,139


$
Future Net Income

$
709,030


$
567,196


$
567,196Present Value at 10% Discount
    Rate(6)

$
349,532


$
279,688


$
279,688Standardized 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. 
 64




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##### Table of Contents



Changes in
    Estimated Proved Reserves
 
    
 OilOil


Natural Gas


Equivalents(MBbls)


(MMcf)


(MBoe)Proved Reserves:Balance, January 1, 2008


16,177



67,009



27,345Revisions of prior
    estimates(1)


(4,374
)


23,731



(419
)Production


(1,084
)


(8,868
)


(2,562
)Balance, December 31, 2008


10,719



81,872



24,364Revisions of prior
    estimates(1)


2,466



2,705



2,917Production


(1,016
)


(8,455
)


(2,425
)Balance, December 31, 2009


12,169



76,122



24,856Revisions of prior
    estimates(1)


1,536



16,836



4,342Production


(939
)


(7,171
)


(2,134
)Balance, December 31, 2010


12,766



85,787



27,064Proved Developed Reserves:Balance, December 31, 2008


10,674



67,164



21,868Balance, December 31, 2009


12,124



57,010



21,626Balance, December 31, 2010


12,387



51,293



20,935Proved Undeveloped Reserves:Balance, December 31, 2008


45



14,708



2,496Balance, December 31, 2009


45



19,112



3,230Balance, 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. 
 
 
 
   
 
   
 65




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##### Table of Contents



Reserve
    Estimates
 
   
  Changes in Proved
    Undeveloped Reserves
 
 
  Permian Basin
    Region
 
 
   
 
   
 
  East
    Texas/North Louisiana Region
 
 
   
 
   
 
  Development of
    Proved Undeveloped Reserves
 
 
   
 66




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##### Table of Contents



Sale and
    Abandonment of Underlying Properties
    12-month
 
  Hydraulic
    Fracturing
 
 
   
 
   
 
   
 
   
 67




---



##### Table of Contents



Marketing and
    Post-Production Services
     68




---



##### Table of Contents



month-to-month
  Title to
    Properties
      
    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
    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.   69




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##### Table of Contents



70




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##### Table of Contents



Competition and
    Markets
       
 
  Environmental
    Matters and Regulation
  General.
  
    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. 
   
 71




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##### Table of Contents



Hazardous substance and wastes.
 
     72




---



##### Table of Contents



Water discharges and hydraulic fracturing.
 
   
 
   
 73




---



##### Table of Contents



Air emissions.
 
  Climate change.
  and/or
 
   
 74




---



##### Table of Contents



National Environmental Policy Act.
 
 
  Endangered Species Act. Sceloporus arenicolus
 
 75




---



##### Table of Contents



Employee health and safety. right-to-know
 76




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##### Table of Contents



COMPUTATION OF
    NET PROFITS    Net Profits
    Interest
   
  Gross profits take-or-pay
 
 
  Net profits
 
  
    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; 77




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##### Table of Contents




    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 (in respect of hedges existing
    prior to the date of the conveyance, as further described in the
    conveyance);
    all hedge settlement costs paid (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).   
   
 78




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Additional
    Provisions
    
    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.     
  12-month
 
     79




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DESCRIPTION OF
    THE TRUST AGREEMENT    Creation and
    Organization of the Trust; Amendments
 
   
   
   
 
   
    
    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. 
   
 81




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##### Table of Contents



Assets of the
    Trust
    Duties and Powers
    of the Trustee
    
    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 and advisable to best
    achieve the purposes of the trust. 
   
   82




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##### Table of Contents




    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.   
   
    
    the sale does not involve a material part of the trusts
    assets; or
    the sale constitutes a material part of the trusts assets,
    subject to the approval of the holders of at least 75% of the
    outstanding trust units.            Fees and
    Expenses
 
   
 83




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Fiduciary
    Responsibility and Liability of the Trustee
 
   
  
    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.       84




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##### Table of Contents



Duration of the
    Trust; Sale of the Net Profits Interest
    
    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.    Dispute
    Resolution
    Compensation of
    the Trustee and the Delaware Trustee
    Miscellaneous
  1-800-852-1422.
   85




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##### Table of Contents



DESCRIPTION OF
    THE TRUST UNITS   
  Distributions and
    Income Computations
 
   
    Transfer of
    Trust Units
    Periodic
    Reports
 
   
   86




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##### Table of Contents



Liability of
    Trust Unitholders
 
   
  Voting Rights of
    Trust Unitholders
      
    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). 
   
  Comparison of
    Trust Units and Common Stock
   87




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##### Table of Contents



Trust Units

Common StockVoting

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.  88




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##### Table of Contents



TRUST UNITS
    ELIGIBLE FOR FUTURE SALE  General
   
  lock-up
 
  Lock-Up
    Agreements
 
  lock-up lock-up
 
  Rule 144
    
    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. 
   
 89




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##### Table of Contents



Registration
    Rights
   
  
    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 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; or
    become eligible for resale pursuant to Rule 144 (or any
    similar rule then in effect under the Securities Act).     90




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FEDERAL INCOME
    TAX CONSEQUENCES  U.S. Federal
    Income Tax Consequences
    non-U.S. trust non-U.S. jurisdiction.
  
    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.
 91




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##### Table of Contents




    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.  non-U.S. trust
 
   
  Classification
    and Taxation of the Trust
   
   
    Reporting
    Requirements for Widely-Held Fixed Investment
    Trusts
   92




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Direct
    Taxation of Trust Unitholders
       
   
  Tax
    Classification of the Net Profits Interest
     93




---



##### Table of Contents



Tax Consequences
    to U.S. Trust Unitholders
  Royalty Income
    and Depletion
         94




---



##### Table of Contents



Tax
    Rates
   
   
  Non-Passive
    Activity Income and Loss
   95




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##### Table of Contents



Disposition of
    Trust Units
    Trust Administrative
    Expenses
    Backup
    Withholding
    Tax Treatment
    Upon Sale of the Net Profits Interest
    Tax Consequences
    to Non-U.S.
    Trust Unitholders
  non-U.S. trust Non-U.S. trust
  Payments with
    Respect to the Trust Units
  non-U.S. trust non-U.S. trust
 96




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Sale or
    Exchange of Trust Units
  non-U.S. trust
  
    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.  non-U.S. trust non-U.S. trust
  Tax Consequences
    to Tax Exempt Organizations
     97




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STATE TAX
    CONSIDERATIONS           98




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ERISA
    CONSIDERATIONS   
    
    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. 
   
 
   
 99




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SELLING
    TRUST UNITHOLDER  30-day
 
    
 Ownership of Trust

Number of

Ownership of Trust Units AfterUnits Before Offering

Trust Units

OfferingSelling Trust Unitholder

Number

Percentage

Being Offered

Number

PercentageEnduro Sponsor


[     ]



100.0
%


[
](1)


[     ]



[     ]
%  
   
  (1)
    
    Includes
    [          ] trust
    units subject to purchase by the underwriters pursuant to their
    30-day option to purchase additional units. 
   100




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##### Table of Contents



UNDERWRITING
    (CONFLICTS OF INTEREST)    
 Number ofUnderwriters

Trust UnitsBarclays Capital Inc.


[          ]Citigroup Global Markets Inc.


[          ]Goldman, Sachs & Co.


[          ]RBC Capital Markets, LLC


[          ]Wells Fargo Securities, LLC


[          ]Total


[          ]  
    
    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.    Commissions and
    Expenses
    No Exercise

Full ExercisePer trust unitTotal    
   
 
   
 101




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##### Table of Contents



Option to
    Purchase Additional Trust Units
 
   
  Lock-Up
    Agreements
 
   
  180-day
  
    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,  18-day
 
  lock-up lock-up
 
  180-day lock-up lock-up
 102




---



##### Table of Contents



Offering Price
    Determination
 
   
 
  
    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
 
   
  Directed Unit
    Program
 
  180-day  Lock-Up
 
  Stabilization,
    Short Positions and Penalty Bids
 
   
  
    Stabilizing transactions permit bids to purchase the underlying
    security so long as the stabilizing bids do not exceed a
    specified maximum.
    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 103




---



##### Table of Contents



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 representative 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. 
      Electronic
    Distribution
  and/or
  and/or
  New York Stock
    Exchange
 
   
  Discretionary
    Sales
   104




---



##### Table of Contents



Conflicts of
    Interest/FINRA Rules
 
 
   
 
   
 
  and/or and/or and/or
 
 105




---



##### Table of Contents



LEGAL
    MATTERS   
 EXPERTS    F-1
 WHERE YOU CAN
    FIND MORE INFORMATION  http://www.sec.gov.
 
 
   
 106




---



##### Table of Contents



GLOSSARY OF
    CERTAIN OIL AND NATURAL GAS TERMS    Bbl
  Boe
  Btu
  Completion
  Development Well
  Differential
  Estimated future net revenues
  Farm-in or farm-out agreement
  Field and/or
  Gross acres or gross wells
  Horizontal well
  MBbl
  MBoe
  Mcf
  MMBoe
  MMBtu
  MMcf
  Net acres or net wells
  Net profits interest
 107




---



##### Table of Contents



Net revenue interest
  Plugging and abandonment
  Proved developed reserves
  Proved reserves
  12-month first-day-of-the-month
    and/or
 108




---



##### Table of Contents



Proved undeveloped reserves
  PV-10
  Recompletion
  Reservoir and/or
  Working interest
  Workover
 109




---



##### Table of Contents



INDEX TO
    FINANCIAL STATEMENTS  
 PREDECESSOR UNDERLYING PROPERTIES:Unaudited Statements of Revenues and Direct
    Operating Expenses for the Three Months Ended March 31,
    2011 and 2010


F-2Notes to Unaudited Statements of Revenues and
    Direct Operating Expenses


F-3Report of Independent Registered Public
    Accounting Firm


F-4Statements of Revenues and Direct Operating
    Expenses for Each of the Three Years in the Period Ended
    December 31, 2010


F-5Notes to Statements of Revenues and Direct
    Operating Expenses


F-6SAMSON PERMIAN BASIN ASSETS:Unaudited Statements of Revenues and Direct
    Operating Expenses for the Three Months Ended March 31,
    2011 and 2010


F-11Notes to Unaudited Statements of Revenues and
    Direct Operating Expenses


F-12Report of Independent Registered Public
    Accounting Firm


F-13Statements of Revenues and Direct Operating
    Expenses for Each of the Three Years in the Period Ended
    December 31, 2010


F-14Notes to Statements of Revenues and Direct
    Operating Expenses


F-15CONOCOPHILLIPS PERMIAN BASIN ASSETS:Unaudited Statements of Revenues and Direct
    Operating Expenses for the Three Months Ended March 31,
    2011 and 2010


F-19Notes to Unaudited Statements of Revenues and
    Direct Operating Expenses


F-20Report of Independent Registered Public
    Accounting Firm


F-21Statements of Revenues and Direct Operating
    Expenses for Each of the Three Years in the Period Ended
    December 31, 2010


F-22Notes to Statements of Revenues and Direct
    Operating Expenses


F-23UNAUDITED PRO FORMA COMBINED UNDERLYING PROPERTIES:Introduction


F-27Unaudited Pro Forma Combined Statements of
    Revenues and Direct Operating Expenses for the Three Months
    Ended March 31, 2011 and for the Years Ended
    December 31, 2010 and 2009


F-28ENDURO ROYALTY TRUST:Report of Independent Registered Public
    Accounting Firm


F-31Statement of Assets and Trust Corpus as of
    May 12, 2011


F-32Notes to Statement of Assets and
    Trust Corpus


F-33Unaudited Pro Forma Financial Statements:Introduction


F-35Unaudited Pro Forma Statement of Assets and
    Trust Corpus as of May 12, 2011


F-36Unaudited Pro Forma Statements of Distributable
    Income for the Three Months Ended March 31, 2011 and for
    the Year Ended December 31, 2010


F-37Notes to Unaudited Pro Forma Financial
    Statements


F-38  
  The audited
    financial statements of the Predecessor can be found beginning
    on
    page ENDURO F-1.
 F-1




---



##### Table of Contents



PREDECESSOR
    UNDERLYING PROPERTIES



UNAUDITED
    STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES  
 Three Months Ended March 31,2011


2010(In thousands)Revenues:Oil

$
335


$
433Natural gas


4,477



6,632Total revenues


4,812



7,065Direct operating expenses:Lease operating


1,238



1,118Gathering and processing


386



307Production and other taxes


243



426Total direct operating expenses


1,867



1,851Excess of revenues over direct operating expenses

$
2,945


$
5,214  
 
   
 F-2




---



##### Table of Contents



PREDECESSOR
    UNDERLYING PROPERTIES



NOTES TO
    UNAUDITED STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES  1.
    Basis of
    Presentation 
 
   
 
   
 
   
 
   
 
  2.
    Contingencies 
 
   
 
  3.
    Cash Flow
    Information 
 
   
 
  4.
    Subsequent
    Events 
 
   
 F-3




---



##### Table of Contents



Report of
    Independent Registered Public Accounting Firm            
    F-4




---



##### Table of Contents



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


$
3,057Natural gas


21,112



22,519



54,485Total revenues


22,457



24,204



57,542Direct operating expenses:Lease operating


4,484



5,365



4,695Gathering and processing


1,522



1,474



2,471Production and other taxes


1,373



1,965



2,259Total direct operating expenses


7,379



8,804



9,425Excess of revenues over direct operating expenses

$
15,078


$
15,400


$
48,117    F-5




---



##### Table of Contents



PREDECESSOR
    UNDERLYING PROPERTIES
  NOTES TO
    STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES
  1.
    Basis of
    Presentation     
   
  Rules 3-01 3-02 Regulation S-X
  2.
    Significant
    Accounting Policies  (a)
    Use of
    Estimates    (b)
    Revenue
    Recognition    (c)
    Direct
    Operating Expenses   F-6




---



##### Table of Contents



PREDECESSOR
    UNDERLYING PROPERTIES
  NOTES TO
    STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES  (Continued)
  and/or
  3.
    Contingencies    4.
    Cash Flow
    Information    5.
    Subsequent
    Events    6.
    Supplemental Oil
    and Natural Gas Disclosures
    (Unaudited)  Extractive Activities  Oil and Gas
  Oil and
    Natural Gas Reserve Quantities
 
   
 F-7




---



##### Table of Contents



PREDECESSOR
    UNDERLYING PROPERTIES
  NOTES TO
    STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES  (Continued)
      Oil


Natural Gas


Total(MBbls)


(MMcf)


(MBOE)January 1, 2008


114



38,126



6,468Revisions of previous estimates


70



26,511



4,489Production


(33
)


(6,449
)


(1,108
)December 31, 2008


151



58,188



9,849Revisions of previous estimates


(16
)


2,490



399Production


(31
)


(6,069
)


(1,043
)December 31, 2009


104



54,609



9,205Revisions of previous estimates


(61
)


14,673



2,385Production


(18
)


(4,976
)


(847
)December 31, 2010


25



64,306



10,743Proved developed reserves as of:December 31, 2008


106



43,480



7,353December 31, 2009


59



35,497



5,975December 31, 2010


25



31,105



5,209Proved undeveloped reserves as of:December 31, 2008


45



14,708



2,496December 31, 2009


45



19,112



3,230December 31, 2010






33,201



5,534   Standardized
    Measure of Discounted Future Net Cash Flows
  12-month 12-month
 F-8




---



##### Table of Contents



PREDECESSOR
    UNDERLYING PROPERTIES
  NOTES TO
    STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES  (Continued)
    December 31,2010


2009


2008Oil (per Bbl)

$
79.43


$
61.18


$
44.60Natural gas (per Mcf)

$
4.37


$
3.83


$
5.62         Year Ended December 31,2010


2009


2008(In thousands)Future cash inflows

$
263,643


$
200,931


$
311,799Future 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



177,86910% 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  F-9




---



##### Table of Contents



PREDECESSOR
    UNDERLYING PROPERTIES
  NOTES TO
    STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES  (Continued)
    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



53,925Development costs incurred during the period


7,779



16,926



26,841Accretion of discount


4,567



9,608



9,827Change in estimated future development costs


(17,147
)


(11,963
)


(30,633
)Timing and other


(3,807
)


(8,187
)


13,527Net change in standardized measure


23,882



(50,406
)


(2,184
)Standardized measure, beginning of year


45,675



96,081



98,265Standardized measure, end of year

$
69,557


$
45,675


$
96,081  F-10




---



##### Table of Contents



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


$
4,289Natural gas


1,213



1,680Total revenues


5,564



5,969Direct operating expenses:Lease operating


785



919Gathering and processing


56



56Production and other taxes


377



441Total direct operating expenses


1,218



1,416Excess of revenues over direct operating expenses

$
4,346


$
4,553    F-11




---



##### Table of Contents



SAMSON PERMIAN
    BASIN ASSETS



NOTES TO
    UNAUDITED STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES  1.
    Basis of
    Presentation     
   
 
   
  2.
    Contingencies   
  3.
    Cash Flow
    Information 
 
   
 
  4.
    Subsequent
    Events 
 
   
 F-12




---



##### Table of Contents



Report of
    Independent Registered Public Accounting Firm            
    F-13




---



##### Table of Contents



SAMSON PERMIAN
    BASIN ASSETS
  STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES
  Year Ended December 31,2010


2009


2008(In thousands)Revenues:Oil

$
16,626


$
13,174


$
23,730Natural gas


5,650



4,733



9,770Total revenues


22,276



17,907



33,500Direct operating expenses:Lease operating


3,438



3,783



4,327Gathering and processing


212



177



178Production and other taxes


1,702



1,558



2,549Total direct operating expenses


5,352



5,518



7,054Excess of revenues over direct operating expenses

$
16,924


$
12,389


$
26,446    F-14




---



##### Table of Contents



SAMSON PERMIAN
    BASIN ASSETS



NOTES TO
    STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES  1.
    Basis of
    Presentation     
   
  Rules 3-01 3-02 Regulation S-X
  2.
    Significant
    Accounting Policies  (a)
    Use of
    Estimates    (b)
    Revenue
    Recognition    (c)
    Direct
    Operating Expenses   F-15




---



##### Table of Contents



SAMSON PERMIAN
    BASIN ASSETS
  NOTES TO
    STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES  (Continued)
  and/or
  3.
    Contingencies    4.
    Cash Flow
    Information (Unaudited)    5.
    Subsequent
    Events    6.
    Supplemental Oil
    and Natural Gas Disclosures
    (Unaudited)  Extractive Activities  Oil and Gas
  Oil and
    Natural Gas Reserve Quantities
 
   
 F-16




---



##### Table of Contents



SAMSON PERMIAN
    BASIN ASSETS
  NOTES TO
    STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES  (Continued)
      Oil


Natural Gas


Total(MBbls)


(MMcf)


(MBOE)January 1, 2008


3,835



14,399



6,235Revisions of previous estimates


(351
)


(517
)


(437
)Production


(246
)


(1,164
)


(440
)December 31, 2008


3,238



12,718



5,358Revisions of previous estimates


139



(150
)


114Production


(233
)


(1,110
)


(418
)December 31, 2009


3,144



11,458



5,054Revisions of previous estimates


120



379



183Production


(216
)


(1,056
)


(392
)December 31, 2010


3,048



10,781



4,845Proved developed reserves as of:December 31, 2008


3,238



12,718



5,358December 31, 2009


3,144



11,458



5,054December 31, 2010


3,048



10,781



4,845   Standardized
    Measure of Discounted Future Net Cash Flows
  12-month 12-month
    December 31,2010

2009

2008Oil (per Bbl)

$
79.43


$
61.18


$
44.60Natural gas (per Mcf)

$
4.37


$
3.83


$
5.62    F-17




---



##### Table of Contents



SAMSON PERMIAN
    BASIN ASSETS
  NOTES TO
    STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES  (Continued)
        Year Ended December 31,2010


2009


2008(In thousands)Future cash inflows

$
292,253


$
239,673


$
224,628Future production costs


(107,372
)


(96,804
)


(92,314
)Future net cash flows


184,881



142,869



132,31410% 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     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



16,207Timing and other


(2,276
)


(5,011
)


4,330Net change in standardized measure


16,071



1,120



(94,306
)Standardized measure, beginning of year


68,883



67,763



162,069Standardized measure, end of year

$
84,954


$
68,883


$
67,763  F-18




---



##### Table of Contents



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


$
12,632Natural gas


1,572



1,526Total revenues


17,036



14,158Direct operating expenses:Lease operating


4,162



4,169Gathering and processing


47



56Production and other taxes


1,385



1,185Total direct operating expenses


5,594



5,410Excess of revenues over direct operating expenses

$
11,442


$
8,748  
 
   
 F-19




---



##### Table of Contents



CONOCOPHILLIPS
    PERMIAN BASIN ASSETS



NOTES TO
    UNAUDITED STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES  1.
    Basis of
    Presentation 
 
   
 
   
 
   
 
   
 
  2.
    Contingencies 
 
   
 
  3.
    Cash Flow
    Information 
 
   
 
  4.
    Subsequent
    Events 
 
   
 F-20




---



##### Table of Contents



Report of
    Independent Registered Public Accounting Firm                F-21




---



##### Table of Contents



CONOCOPHILLIPS
    PERMIAN BASIN ASSETS
  STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES
  Year Ended December 31,2010


2009


2008(In thousands)Revenues:Oil

$
52,062


$
40,450


$
80,014Natural gas


7,025



5,801



11,746Total revenues


59,087



46,251



91,760Direct operating expenses:Lease operating


16,657



16,674



20,309Gathering and processing


243



234



386Production and other taxes


4,994



3,989



6,409Total direct operating expenses


21,894



20,897



27,104Excess of revenues over direct operating expenses

$
37,193


$
25,354


$
64,656    F-22




---



##### Table of Contents



CONOCOPHILLIPS
    PERMIAN BASIN ASSETS
  NOTES TO
    STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES
  1.
    Basis of
    Presentation     
   
  Rules 3-01 Regulation S-X
  2.
    Significant
    Accounting Policies  (a)
    Use of
    Estimates    (b)
    Revenue
    Recognition    (c)
    Direct
    Operating Expenses  and/or
 F-23




---



##### Table of Contents



CONOCOPHILLIPS
    PERMIAN BASIN ASSETS
  NOTES TO
    STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES  (Continued)
    3.
    Contingencies    4.
    Cash Flow
    Information (Unaudited)    5.
    Subsequent
    Events    6.
    Supplemental Oil
    and Natural Gas Disclosures
    (Unaudited)  Extractive Activities  Oil and Gas
  Oil and
    Natural Gas Reserve Quantities
 
   
 F-24




---



##### Table of Contents



CONOCOPHILLIPS
    PERMIAN BASIN ASSETS
  NOTES TO
    STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES  (Continued)
    Oil


Natural Gas


Total(MBbls)


(MMcf)


(MBOE)January 1, 2008


12,228



14,484



14,642Revisions of previous estimates


(4,093
)


(2,263
)


(4,470
)Production


(805
)


(1,255
)


(1,014
)December 31, 2008


7,330



10,966



9,158Revisions of previous estimates


2,343



365



2,404Production


(752
)


(1,276
)


(965
)December 31, 2009


8,921



10,055



10,597Revisions of previous estimates


1,477



1,784



1,774Production


(705
)


(1,139
)


(895
)December 31, 2010


9,693



10,700



11,476Proved developed reserves as of:December 31, 2008


7,330



10,966



9,158December 31, 2009


8,921



10,055



10,597December 31, 2010


9,314



9,407



10,882Proved 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
  12-month 12-month
    December 31,2010

2009

2008Oil (per Bbl)

$
79.43


$
61.18


$
44.60Natural gas (per Mcf)

$
4.37


$
3.83


$
5.62    F-25




---



##### Table of Contents



CONOCOPHILLIPS
    PERMIAN BASIN ASSETS
  NOTES TO
    STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES  (Continued)
        Year Ended December 31,2010


2009


2008(In thousands)Future cash inflows

$
788,822


$
562,323


$
378,542Future production costs


(407,974
)


(331,913
)


(228,540
)Future development costs


(6,000
)






Future net cash flows


374,848



230,410



150,00210% 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     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



36,168Change 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



361,679Standardized measure, end of year

$
195,021


$
127,406


$
88,574  F-26




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##### Table of Contents



UNAUDITED PRO
    FORMA COMBINED STATEMENTS OF REVENUES
    AND DIRECT OPERATING EXPENSES OF THE UNDERLYING
    PROPERTIES  Introduction
 
 
   
 
   
   F-27




---



##### 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


TotalUnderlying


Permian Basin


Permian Basin


UnderlyingProperties


Assets


Assets


Properties(In thousands)Revenues:Oil

$
335


$
4,351


$
15,464


$
20,150Natural gas


4,477



1,213



1,572



7,262Total revenues


4,812



5,564



17,036



27,412Direct operating expenses:Lease operating


1,238



785



4,162



6,185Gathering and processing


386



56



47



489Production and other taxes


243



377



1,385



2,005Total direct operating expenses


1,867



1,218



5,594



8,679Excess of revenues over direct operating expenses

$
2,945


$
4,346


$
11,442


$
18,733  
 F-28




---



##### Table of Contents



UNAUDITED PRO
    FORMA COMBINED STATEMENT OF REVENUES
    AND DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES
    YEAR ENDED DECEMBER 31, 2010
 
 
 
  
 Predecessor


Samson


ConocoPhillips


TotalUnderlying


Permian Basin


Permian Basin


UnderlyingProperties


Assets


Assets


Properties(In thousands)Revenues:Oil

$
1,345


$
16,626


$
52,062


$
70,033Natural gas


21,112



5,650



7,025



33,787Total revenues


22,457



22,276



59,087



103,820Direct operating expenses:Lease operating


4,484



3,438



16,657



24,579Gathering and processing


1,522



212



243



1,977Production and other taxes


1,373



1,702



4,994



8,069Total direct operating expenses


7,379



5,352



21,894



34,625Excess of revenues over direct operating expenses

$
15,078


$
16,924


$
37,193


$
69,195  
 F-29




---



##### Table of Contents



UNAUDITED PRO
    FORMA COMBINED STATEMENT OF REVENUES
    AND DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES
    YEAR ENDED DECEMBER 31, 2009
 
  
 Predecessor


Samson


ConocoPhillips


TotalUnderlying


Permian Basin


Permian Basin


UnderlyingProperties


Assets


Assets


Properties(In thousands)Revenues:Oil

$
1,685


$
13,174


$
40,450


$
55,309Natural gas


22,519



4,733



5,801



33,053Total revenues


24,204



17,907



46,251



88,362Direct operating expenses:Lease operating


5,365



3,783



16,674



25,822Gathering and processing


1,474



177



234



1,885Production and other taxes


1,965



1,558



3,989



7,512Total direct operating expenses


8,804



5,518



20,897



35,219Excess of revenues over direct operating expenses

$
15,400


$
12,389


$
25,354


$
53,143  
 F-30




---



##### Table of Contents



Report of
    Independent Registered Public Accounting Firm            
    F-31




---



##### Table of Contents



ENDURO ROYALTY
    TRUST



STATEMENT OF
    ASSETS AND TRUST CORPUS  May 12, 2011ASSETSCash

$
10TRUST CORPUSTrust Corpus

$
10    F-32




---



##### Table of Contents



ENDURO ROYALTY
    TRUST



NOTES TO
    STATEMENT OF ASSETS AND TRUST CORPUS  1.
    Organization of
    the Trust       
 
    2.
    Trust Significant
    Accounting Policies  (a)
    Basis of
    Accounting             F-33




---



##### Table of Contents



ENDURO ROYALTY
    TRUST
  NOTES TO
    STATEMENT OF ASSETS AND
    TRUST CORPUS  (Continued)
  unit-of-production
    Financial
    Statements of Royalty Trusts
    (b)
    Use of
    Estimates    3.
    Income
    Taxes    4.
    Distributions to
    Unitholders   F-34




---



##### Table of Contents



ENDURO ROYALTY
    TRUST
  UNAUDITED PRO
    FORMA FINANCIAL STATEMENTS
 
 Introduction   
   
   
 
   
 F-35




---



##### Table of Contents



ENDURO ROYALTY
    TRUST
 UNAUDITED PRO
    FORMA STATEMENT OF ASSETS AND TRUST CORPUS  
 May 12, 2011Historical


Adjustments


Pro Forma(In thousands)ASSETSCash

$



$



$
Investment in Net Profits Interest (See Note 5)






700,000



700,000$



$
700,000


$
700,000TRUST CORPUSTrust Units Issued and Outstanding

$



$
700,000


$
700,000  
   F-36




---



##### Table of Contents



ENDURO ROYALTY
    TRUST
 
 UNAUDITED PRO
    FORMA STATEMENTS OF DISTRIBUTABLE INCOME  
 Three MonthsEnded


Year EndedMarch 31, 2011


December 31, 2010(In thousands)Historical ResultsIncome from the Net Profits Interest (See Note 4)

$
5,302


$
25,727Pro Forma AdjustmentsLess: Trust general and administrative expenses (See Note 5)


213



850Distributable income

$
5,089


$
24,877Distributable income per unit

$
[   ]


$
[   ]  
   F-37




---



##### Table of Contents



ENDURO ROYALTY
    TRUST
  NOTES TO
    UNAUDITED PRO FORMA FINANCIAL STATEMENTS
  1.
    Basis of
    Presentation   
   
 
   
 
   
  2.
    Trust Accounting
    Policies   
   
   
   
 F-38




---



##### Table of Contents



ENDURO ROYALTY
    TRUST
  NOTES TO
    UNAUDITED PRO FORMA FINANCIAL
    STATEMENTS  (Continued)
  3.
    Income
    Taxes    4.
    Income from Net
    Profits Interest 
   
  
 Three Months Ended


Year EndedMarch 31, 2011


December 31, 2010Pro forma excess of revenues over direct operating expenses of
    the Underlying Properties

$
18,733


$
69,195Development
    costs(a)


(12,105
)


(37,036
)Excess of revenues over direct operating expenses and
    development costs


6,628



32,159Multiplied 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 
   
  Gross cash proceeds from the sale of trust units

$
350,000Trust units held by Enduro Sponsor


350,000Fair value of investment in Net Profits Interest

$
700,000  
   
 F-39




---



##### Table of Contents



INFORMATION
    ABOUT
    ENDURO RESOURCE PARTNERS LLC
    (ENDURO SPONSOR)
  The trust units
    are not interests in or obligations of
    Enduro Sponsor
 ENDURO-1




---



##### Table of Contents



Business and
    Properties of Enduro Sponsor
 
   
 
   
  PV-10
  The trust units do not represent interests in, or obligations
    of, Enduro Sponsor
 
  Management of
    Enduro Sponsor
 
 
   
  
 Name

Age

TitleJon S. Brumley


40


President and Chief Executive OfficerJohn W. Arms


44


Executive Vice President and Chief Operating OfficerKimberly A. Weimer


32


Vice President and Chief Financial OfficerBill R. Pardue


38


Director, Engineering and OperationsDavid J. Grahek


57


Director, GeologyDavid Leuschen


60


ManagerPierre F. Lapeyre, Jr.


48


ManagerN. John Lancaster


43


ManagerI. Jon Brumley


72


Manager  
 
  Jon S. Brumley
 
 ENDURO-2




---



##### Table of Contents



John W. Arms
 
 
  Kimberly A. Weimer
 
 
  Bill R. Pardue
 
 
  David J. Grahek
 
 
  David Leuschen
 
 ENDURO-3




---



##### Table of Contents



Pierre F. Lapeyre, Jr. 14-year
 
 
  N. John Lancaster
 
 
  I. Jon Brumley
 
 
 
 
  Compensation
    Discussion and Analysis
 
 
   
 
  
    Jon S. Brumley, President and Chief Executive Officer of Enduro
    Sponsor, 
 ENDURO-4




---



##### Table of Contents




    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. 
 
   
 
 
 
  Overview
 
 
   
 
  
    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. 
 
   
 
  Setting
    Executive Compensation
 
 
   
 ENDURO-5




---



##### Table of Contents



Elements of
    Compensation
 
 
   
 
  Base Salary.
 
 
   
  
 Name and Principal Position

2010 Base SalaryJon S. Brumley
    President and Chief Executive Officer

$
325,000John W. Arms
    Executive Vice President and Chief Operating Officer

$
325,000Kimberly A. Weimer
    Vice President and Chief Financial Officer

$
165,000Bill R. Pardue
    Director, Engineering and Operations

$
165,000David J. Grahek
    Director, Geology

$
165,000  
 
   
 
  Discretionary Cash Bonus Awards.
 
 
   
 
   
 ENDURO-6




---



##### Table of Contents



Long-Term Equity-Based Compensation
    Awards.
 
 
  Change-in-Control
 
 
  Additional
    Benefits
 
 
   
 
  Employment and
    Severance Arrangements
 
 
   
 
   
 ENDURO-7




---



##### Table of Contents



Summary
    Compensation Table for 2010
 
 
   
  
 Name andPrincipal Position

Year


Salary(1)


Bonus(2)


Unit
    Awards(3)


TotalJon S. Brumley


2010


$
236,528


$
162,500






$
399,028President and Chief Executive OfficerJohn W. Arms


2010


$
236,528


$
162,500






$
399,028Executive Vice President and Chief Operating OfficerKimberly A. Weimer


2010


$
120,083


$
82,500






$
202,583Vice President and Chief Financial OfficerBill R. Pardue


2010


$
103,125


$
57,750






$
160,875Director, Engineering and OperationsDavid J. Grahek


2010


$
72,558


$
57,750






$
130,308Director, 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 
 ENDURO-8




---



##### Table of Contents



date fair value of these awards was nominal and a value of $0
    was assigned for purposes of the above table. 
 
  Grants of
    Plan-Based Awards for 2010
 
 
   
  
 All Other Unit


Grant Date FairAwards: Number of


Value of UnitsName

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
 
 
   
  
 Unit AwardsNumber of


Market Value ofClass B Units


Class B UnitsThat Have Not


That Have NotName

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
 
 
   
 
  Pension
    Benefits for 2010
 
 
   
 ENDURO-9




---



##### Table of Contents



Nonqualified
    Deferred Compensation
 
 
   
 
  Potential
    Payments upon Termination or
    Change-in-Control
 
 
   
  
 Termination for Convenience or Due toName

Payment Type


Resignation for Good Reason
    ($)(1)Jon S. Brumley


Salary



325,000Bonus



162,500Total


$
487,500John W. Arms


Salary



325,000Bonus



162,500Total


$
487,500Kimberly A. Weimer


Salary



165,000Bonus



82,500Total


$
247,500Bill R. Pardue


Salary



165,000Bonus



57,750Total


$
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. 
 
   
 
  Resignation for Good Reason or Termination Without Cause or
    Due to Death or Disability.
 
 ENDURO-10




---



##### Table of Contents



Resignation Without Good Reason.
 
 
  Termination for Cause.
 
 
   
 
   
 
  Director
    Compensation For 2010
 
 
   
  Litigation
   ENDURO-11




---



##### Table of Contents



Indemnification
 
   
 
  Selected
    Historical and Unaudited Pro Forma Financial Data of Enduro
    Sponsor
 
 
   
 
   
 
   
 
  
 ENDURO-12




---



##### Table of Contents



Enduro


Enduro SponsorSponsor


Pro Forma


Enduro


Enduro SponsorPro Forma


as Adjusted


Sponsor


Pro Formafor the


for the Offering


Pro Forma


as AdjustedAcquisition


(including the


for the


for the Offeringof the


Conveyance of the


Acquisition


(including the


Enduro Sponsor







Predecessor Acquired


Net Profits


of the


Conveyance of the





March 3,







DNR



Predecessor  EACProperties


Interest)


Acquired


Net Profits





2010



Enduro Sponsor



March 9,



January 1,Three Months


Three Months


Properties


Interest)


Three Months


(Inception)



Inception



2010



2010Ended


Ended


Year Ended


Year Ended


Ended


Through



Through



Through



Through


Year EndedMarch 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)RevenuesOil

$
20,202


$
18,253


$
70,161


$
61,483


$
10,236


$




$
106



$
1,036



$
331


$
1,909


$
3,295Natural Gas


12,774



12,072



62,420



58,234



11,899








3,486




35,503




10,756



31,998



59,075Marketing


817



817



5,131



5,131



817








383




3,671




1,077







Total revenues

$
33,793


$
31,142


$
137,712


$
124,848


$
22,952


$




$
3,975



$
40,210



$
12,164


$
33,907


$
62,370ExpensesLease operating

$
6,827


$
6,827


$
27,019


$
27,019


$
4,007


$




$
507



$
5,285



$
1,142


$
7,608


$
6,343Production, ad valorem, and severance taxes


2,330



2,330



9,417



9,417



1,447








170




2,003




548



2,565



2,442Gathering and transportation


835



835



3,845



3,845



794








206




2,755




429



2,138



2,577Depletion, depreciation, and amortization


14,793



10,248



64,723



45,495



10,830








1,973




21,754




7,949



33,665



26,716Exploration expense










10,188



10,188

















9,957




231



8,688



723Marketing


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



4,001Merger-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



28Total expenses

$
41,568


$
37,023


$
137,891


$
118,663


$
33,261


$
77



$
12,049



$
53,542



$
29,985


$
59,760


$
42,830Operating income (loss)

$
(7,775
)

$
(5,881
)

$
(179
)

$
6,185



(10,309
)


(77
)


$
(8,074
)


$
(13,332
)


$
(17,821
)

$
(25,853
)

$
19,540Interest expense, net

$
(1,818
)

$



$
(8,466
)

$




(1,220
)






$
(148
)


$
(6,183
)


$



$



$
Deferred income tax benefit

$
34


$
34


$



$



$
34


$




$




$




$



$



$
Net income (loss)

$
(9,559
)

$
(5,847
)

$
(8,645
)

$
6,185


$
(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.
    Factors that
    Significantly Affect Enduro Sponsors Results
   ENDURO-13




---



##### Table of Contents



Results of
    Operations
 
  Comparison of
    the Quarters Ended March 31, 2011 and 2010
 
 
  Presentation
 
 
   
 ENDURO-14




---



##### Table of Contents



March 3, 2010Three Months Ended


(Inception) ThroughMarch 31, 2011


March 31, 2010(Unaudited)RevenuesOil

$
10,236


$
Natural Gas


11,899



Marketing


817



Total revenues

$
22,952


$
ExpensesLease 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



77Derivative fair value loss


11,449



Other operating


896



Total expenses

$
33,261


$
77Operating 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


$
  
 
   
 
   
 
   
 
   
 ENDURO-15




---



##### Table of Contents



Comparison of
    the Years Ended December 31, 2010 and 2009
  Presentation
 
   
 ENDURO-16




---



##### Table of Contents



Enduro Sponsor



Predecessor - DNR



Predecessor - EACInception



March 9,



January 1,


YearThrough



2010 Through



2010 Through


EndedDecember 31,



November 30,



March 8,


December 31,2010



2010



2010


2009RevenueOil

$
106



$
1,036



$
331


$
1,909Natural gas


3,486




35,503




10,756



31,998Marketing


383




3,671




1,077



Total Revenues

$
3,975



$
40,210



$
12,164


$
33,907ExpensesLease operating

$
507



$
5,285



$
1,142


$
7,608Production, ad valorem and severance taxes


170




2,003




548



2,565Gathering and transportation


206




2,755




429



2,138Depletion, depreciation, and amortization


1,973




21,754




7,949



33,665Exploration expense







9,957




231



8,688Marketing


372




3,588




1,060



General and administrative


3,826




1,254




2,481



5,045Merger related transaction costs







6,922




16,136



Derivative fair value loss


4,977













Other operating


18




24




9



51Total expenses

$
12,049



$
53,542



$
29,985


$
59,760Operating 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 VolumesOil (MBbls)


1




14




5



35Natural Gas (MMcf)


853




8,944




1,941



8,569Total (MBoe)


143




1,505




329



1,463Average sales prices:Oil ($/Bbl)

$
106.00



$
74.00



$
66.20


$
54.54Natural gas ($/Mcf)

$
4.09



$
3.97



$
5.54


$
3.73Average costs per Boe:Lease operating

$
3.55



$
3.51



$
3.47


$
5.20Production, ad valorem and severance taxes

$
1.19



$
1.33



$
1.67


$
1.75Gathering and transportation

$
1.44



$
1.83



$
1.30


$
1.46Depletion, depreciation, and amortization

$
13.80



$
14.45



$
24.16


$
23.01  
   ENDURO-17




---



##### Table of Contents



ENDURO-18




---



##### Table of Contents



Comparison of
    the Years Ended December 31, 2009 and 2008
    
 Predecessor - EACYear Ended December 31,2009


2008RevenueOil

$
1,909


$
3,295Natural gas


31,998



59,075Total Revenues

$
33,907


$
62,370ExpensesLease operating

$
7,608


$
6,343Production, ad valorem and severance taxes


2,565



2,442Gathering and transportation


2,138



2,577Depletion, depreciation, and amortization


33,665



26,716Exploration expense


8,688



723General and administrative


5,045



4,001Other operating


51



28Total expenses

$
59,760


$
42,830Net income (loss)

$
(25,853
)

$
19,540Production VolumesOil (MBbls)


35



36Natural Gas (MMcf)


8,569



6,946Total (MBoe)


1,463



1,193Average realized pricesOil ($/Bbl)

$
54.54


$
91.53Natural gas ($/Mcf)

$
3.73


$
8.50Selected Expenses (per Boe):Lease operating

$
5.20


$
5.32Production, ad valorem and severance taxes

$
1.75


$
2.05Gathering and transportation

$
1.46


$
2.16Depletion, depreciation, and amortization

$
23.01


$
22.39  
 
   
     ENDURO-19




---



##### Table of Contents



Liquidity and
    Capital Resources
   
   
  Cash Flows from
    Operating Activities
 
   
 
   
  Cash Flows from
    Investing Activities
 
   
 ENDURO-20




---



##### Table of Contents



Cash Flows from
    Financing Activities
 
 
   
          
    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.   ENDURO-21




---



##### Table of Contents



Contractual
    Obligations
 
   
  
 Payments Due by PeriodLess Than








More ThanTotal


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


$
5,125Lease 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
 
   
  Critical
    Accounting Policies and Estimates
 
   
  Oil and Natural
    Gas Properties
   ENDURO-22




---



##### Table of Contents



unit-of-production
   
   
  project-by-project
  Oil and Natural
    Gas Reserve Quantities
 
  well-by-well
 
   ENDURO-23




---



##### Table of Contents



Revenue
    Recognition
 
   
     
   
 
   
  Derivatives
 
   
    Asset Retirement
    Obligations
     ENDURO-24




---



##### Table of Contents



Recently
    Issued Accounting Pronouncements
    No. 2010-03, 2010-03) 2010-03
 
   
  Quantitative
    and Qualitative Disclosure about Market Risk
    Commodity Price
    Risk
   ENDURO-25




---



##### Table of Contents



Fair ValueDaily 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


$
976January 2012  December 2012


14,000


$
4.90



10,000


$
4.57


$
2,072January 2013  December 2013


12,000


$
4.90



8,000


$
5.00


$
2,031$
5,079  
 
   
  
 Average


AverageDaily


Average


Daily


Collar


Collar


Daily





Fair ValuePut


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
)  
 
   
  
 Average


Average


Average


Fair ValueDaily


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
 
   
  Description of
    the Enduro Sponsor Limited Liability Company Agreement
 
   
  Organization
    and Duration
   ENDURO-26




---



##### Table of Contents



Business
 
   
  Membership
    Interests; Transferability
 
   
 
   
  Distributions
    of Available Cash
    Management of
    Enduro Sponsor and Fiduciary Duties
    Limited
    Liability
   ENDURO-27




---



##### Table of Contents



Amendment of
    the LLC Agreement
    Dissolution
    Liquidation
    and Termination
 
   
 ENDURO-28




---



##### Table of Contents



INDEX
    TO FINANCIAL STATEMENTS OF ENDURO SPONSOR
  
 ENDURO RESOURCE PARTNERS LLC PREDECESSOR:Report of Independent Registered Public
    Accounting Firm


ENDURO F-2Carve Out Balance Sheets as of November 30,
    2010 and December 31, 2009


ENDURO F-3Carve Out Statements of Operations for the Period
    from March 9, 2010 Through November 30, 2010, the
    Period from January 1, 2010 Through March 8, 2010, and
    the Years Ended December 31, 2009 and 2008


ENDURO F-4Carve Out Statements of Owners Net Equity
    for the Period from March 9, 2010 to November 30,
    2010, the Period from January 1, 2010 to March 8,
    2010, and the Years Ended December 31, 2009 and 2008


ENDURO F-5Carve Out Statements of Cash Flows for the Period
    from March 9, 2010 Through November 30, 2010, the
    Period from January 1, 2010 Through March 8, 2010, and
    the Years Ended December 31, 2009 and 2008


ENDURO F-6Notes to Carve Out Financial Statements


ENDURO F-7ENDURO RESOURCE PARTNERS LLC:Consolidated Balance Sheets as of March 31,
    2011 (Unaudited) and December 31, 2010


ENDURO F-19Unaudited Consolidated Statements of Operations
    for the Three Months Ended March 31, 2011 and for the
    Period from March 3, 2010 (Inception) Through
    March 31, 2010


ENDURO F-20Unaudited Consolidated Statement of Changes in
    Members Equity for the Three Months Ended March 31,
    2011


ENDURO F-21Unaudited Consolidated Statements of Cash Flows
    for the Three Months Ended March 31, 2011 and for the
    Period from March 3, 2010 (Inception) Through
    March 31, 2010


ENDURO F-22Notes to Unaudited Consolidated Financial
    Statements


ENDURO F-23Report of Independent Registered Public
    Accounting Firm


ENDURO F-32Consolidated Balance Sheet as of
    December 31, 2010


ENDURO F-33Consolidated Statement of Operations for the
    Period from March 3, 2010 (Inception) Through
    December 31, 2010


ENDURO F-34Consolidated Statement of Changes in
    Members Equity for the Period from March 3, 2010
    (Inception) Through December 31, 2010


ENDURO F-35Consolidated Statement of Cash Flows for the
    Period from March 3, 2010 (Inception) Through
    December 31, 2010


ENDURO F-36Notes to Consolidated Financial Statements


ENDURO F-37UNAUDITED PRO FORMA FINANCIAL STATEMENTS:Introduction


ENDURO F-52Unaudited Pro Forma Balance Sheet as of
    March 31, 2011


ENDURO F-53Unaudited Pro Forma Statement of Operations for
    the Three Months Ended March 31, 2011


ENDURO F-54Unaudited Pro Forma Statement of Operations for
    the Year Ended December 31, 2010


ENDURO F-55Notes to Unaudited Pro Forma Financial
    Statements


ENDURO F-56  
 ENDURO F-1




---



##### Table of Contents



Report of
    Independent Registered Public Accounting Firm             
    ENDURO F-2




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC PREDECESSOR
  CARVE OUT BALANCE SHEETS
 
  Predecessor-



Predecessor-DNR



EACNovember 30,



December 31,2010



2009(In thousands)ASSETSCurrent assets:Accounts receivable

$
8,287



$
11,771Prepaid drilling costs


1,345




3,778Total current assets


9,632




15,549Oil and natural gas properties  successful efforts
    method:Proved properties


220,237




368,461Unproved properties


199,130




20,792Accumulated depletion, depreciation, and amortization


(31,707
)



(103,722
)Total oil and natural gas properties, net


387,660




285,531Other property and equipment, net


22




47Total assets

$
397,314



$
301,127LIABILITIES AND OWNERS NET EQUITYCurrent liabilities:Accrued lease operating expense

$
1,260



$
1,205Production, ad valorem, and severance taxes payable


929




739Accrued development capital


19,253




15,684Other


554




656Total current liabilities


21,996




18,284Asset retirement obligations


587




1,404Total liabilities


22,583




19,688Commitments and contingenciesOwners net equity


374,731




281,439Total liabilities and owners net equity

$
397,314



$
301,127    ENDURO F-3




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC PREDECESSOR
  CARVE OUT STATEMENTS OF OPERATIONS
 
  Predecessor-DNR



Predecessor-EACMarch 9, 2010



January 1,Through



2010 Through


Year Ended


Year EndedNovember 30,



March 8,


December 31,


December 31,2010



2010


2009


2008(In thousands)Revenues:Oil

$
1,036



$
331


$
1,909


$
3,295Natural gas


35,503




10,756



31,998



59,075Marketing


3,671




1,077







Total revenues


40,210




12,164



33,907



62,370Expenses:Lease operating


5,285




1,142



7,608



6,343Production, ad valorem, and severance taxes


2,003




548



2,565



2,442Gathering and transportation


2,755




429



2,138



2,577Depletion, depreciation, and amortization


21,754




7,949



33,665



26,716Exploration expense


9,957




231



8,688



723Marketing


3,588




1,060







General and administrative


1,254




2,481



5,045



4,001Merger-related transaction costs


6,922




16,136







Other operating


24




9



51



28Total expenses


53,542




29,985



59,760



42,830Operating income (loss)


(13,332
)



(17,821
)


(25,853
)


19,540Interest expense


(6,183
)











Net income (loss)

$
(19,515
)


$
(17,821
)

$
(25,853
)

$
19,540    ENDURO F-4




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC PREDECESSOR
  CARVE OUT STATEMENTS OF OWNERS NET
    EQUITY
 
  Owners Net Equity(In thousands)Predecessor  EACBalance at January 1, 2008

$
105,278Net income


19,540Net contributions from owner


109,615Balance at December 31, 2008


234,433Net loss


(25,853
)Net contributions from owner


72,859Balance at December 31, 2009


281,439Net loss


(17,821
)Net contributions from owner


26,455Balance at March 8, 2010

$
290,073Predecessor  DNRBalance at March 9, 2010

$
Net loss


(19,515
)Net contributions from owner


394,246Balance at November 30, 2010

$
374,731    ENDURO F-5




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC PREDECESSOR
  CARVE OUT STATEMENTS OF CASH FLOWS
 
  Predecessor -DNR



Predecessor - EACMarch 9, 2010



January 1,


Year


YearThrough



2010 Through


Ended


EndedNovember 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
)

$
19,540Adjustments to reconcile net income (loss) to net cash provided
    by (used in) operating activities:Depletion, depreciation, and amortization


21,754




7,949



33,665



26,716Other non-cash items


9,981




240



8,739



751Changes 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



582Net cash provided by (used in) operating activities


23,696




(15,047
)


22,575



35,028Cash 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



109,615Net cash provided by financing activities


394,246




26,455



72,859



109,615Net increase in cash and cash equivalents















Cash and cash equivalents, beginning of period















Cash and cash equivalents, end of period

$




$



$



$
    ENDURO F-6




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC PREDECESSOR
  NOTES
    TO CARVE OUT FINANCIAL STATEMENTS
 
  1.
    Organization and
    Nature of Operations      2.
    Summary of
    Significant Accounting Policies  Basis of
    Presentation
    Regulation S-X, General instructions as to financial
    statements Allocations of Expenses and
    Related Disclosure in Financial Statements of Subsidiaries,
    Divisions or Lesser Business Components of Another Entity.
  Allocation of
    Costs
   ENDURO F-7




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC PREDECESSOR
  NOTES TO CARVE
    OUT FINANCIAL STATEMENTS  (Continued)
 
    Use of
    Estimates
      Cash and Cash
    Equivalents
    Accounts
    Receivable
    Oil and
    Natural Gas Properties
   ENDURO F-8




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC PREDECESSOR
  NOTES TO CARVE
    OUT FINANCIAL STATEMENTS  (Continued)
 
          unit-of-production
      project-by-project
  Other Property
    and Equipment
   ENDURO F-9




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC PREDECESSOR
  NOTES TO CARVE
    OUT FINANCIAL STATEMENTS  (Continued)
 
  Asset
    Retirement Obligations
      Owners
    Net Equity
    Revenue
    Recognition
        Accounting for Purchases and Sales of
 ENDURO F-10




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC PREDECESSOR
  NOTES TO CARVE
    OUT FINANCIAL STATEMENTS  (Continued)
 
 
  Inventory with the Same Counterparty
 
  Income
    Taxes
      Earnings per
    Share
    Segments
    Recently
    Issued Accounting Pronouncements
    No. 2010-03, 2010-03) 2010-03
   ENDURO F-11




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC PREDECESSOR
  NOTES TO CARVE
    OUT FINANCIAL STATEMENTS  (Continued)
 
    3.
    Acquisition      Proved oil and natural gas properties

$
164,154Unproved properties


199,130Other equipment


26Accounts receivable


13,702Prepaid drilling costs


6,003Total assets acquired


383,015Accrued 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     4.
    Disclosures About
    Fair Value Measurements    
    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 ENDURO F-12




---



##### Table of Contents



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.      Assets and
    Liabilities Measured at Fair Value on a Nonrecurring
    Basis
        Concentrations
    of Credit Risk
    Predecessor -DNR


Predecessor - EACMarch 9, 2010




YearThrough


January 1,

Ended

Year EndedNovember 30,


2010 Through

December 31,

December 31,2010


March 8, 2010

2009

2008Camterra 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. ENDURO F-13




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC PREDECESSOR
  NOTES TO CARVE
    OUT FINANCIAL STATEMENTS  (Continued)
 
     5.
    Asset Retirement
    Obligations    Predecessor- DNR



Predecessor - EACJanuary 1,


YearMarch 9, 2010



2010 Through


EndedThrough



March 8,


December 31,November 30, 2010



2010


2009Beginning asset retirement obligations

$




$
1,404


$
1,322Liabilities assumed at acquisition


558








Wells drilled


5








268Change in estimate







(1
)


(237
)Accretion of discount


24




9



51Ending asset retirement obligations

$
587



$
1,412


$
1,404     6.
    Commitments and
    Contingencies  General
    Lease
    Agreements
  month-to-month
  Firm
    Transportation Agreement
 
  10-year
 
 ENDURO F-14




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC PREDECESSOR
  NOTES TO CARVE
    OUT FINANCIAL STATEMENTS  (Continued)
 
    2010

$
2092011


2,4642012


2,4702013


2,4642014


2,4642015


2,464Thereafter


10,059$
22,594   7.
    Subsequent
    Events    8.
    Supplemental Oil
    and Natural Gas Disclosures
    (Unaudited)  Costs Incurred
    for Oil and Natural Gas Producing Activities
  Predecessor-DNR



Predecessor-EACMarch 9



January 1, 2010


Year


YearThrough



Through


Ended


EndedNovember 30,



March 8,


December 31,


December 31,2010



2010


2009


2008(In thousands)Proved acquisitions

$
164,154



$



$



$
56,186Unproved acquisitions


199,130








1,814



14,841Total acquisitions


363,284








1,814



71,027Exploratory costs


9,945




11,534



59,092



29,057Development costs


46,138




4,424



30,742



59,546Total costs incurred

$
419,367



$
15,958


$
91,648


$
159,630  
  Extractive Activities  Oil and Gas
 
  Oil and
    Natural Gas Reserve Quantities
 
   
 ENDURO F-15




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC PREDECESSOR
  NOTES TO CARVE
    OUT FINANCIAL STATEMENTS  (Continued)
 
      Predecessor-DNR


Predecessor-EACNovember 30,


December 31,

December 31,2010


2009

2008Proved reservesOil (MBbl)


112




114



151Natural gas (MMcf)


107,686




108,906



61,239Combined (MBOE)


18,059




18,265



10,357Proved developed reservesOil (MBbl)


67




69



106Natural gas (MMcf)


57,673




53,667



46,378Combined (MBOE)


9,679




9,014



7,836     Oil


Natural Gas


Combined(MBbls)


(MMcf)


(MBOE)Predecessor  EAC:Balance as of January 1, 2008


114



39,495



6,696Revisions of estimates


73



28,690



4,855Production


(36
)


(6,946
)


(1,194
)Balance as of December 31, 2008


151



61,239



10,357Revisions of estimates


(2
)


56,236



9,371Production


(35
)


(8,569
)


(1,463
)Balance as of December 31, 2009


114



108,906



18,265Production


(5
)


(1,941
)


(329
)Balance as of March 8, 2010


109



106,965



17,936Predecessor  DNR:Balance as of March 9, 2010










Acquisitions


126



116,630



19,564Production


(14
)


(8,944
)


(1,505
)Balance as of November 30, 2010


112



107,686



18,059  ENDURO F-16




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC PREDECESSOR
  NOTES TO CARVE
    OUT FINANCIAL STATEMENTS  (Continued)
 
  Standardized
    Measure of Discounted Future Net Cash Flows
  12-month 12-month
        Predecessor-DNR



Predecessor - EACNovember



March 8,


December 31,


December 31,30, 2010



2010


2009


2008Oil and natural gas producing activities:Future cash inflows

$
433,755



$
377,488


$
388,575


$
333,413Future 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



191,84310% 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  ENDURO F-17




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC PREDECESSOR
  NOTES TO CARVE
    OUT FINANCIAL STATEMENTS  (Continued)
 
    Predecessor-DNR



Predecessor-EACMarch 8,



January 1,2010



2010


Year


YearThrough



Through


Ended


EndedNovember 30,



March 8,


December


December2010



2010


31, 2009


31, 2008Oil 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



59,189Previously estimated development costs incurred


56,083




15,958



39,563



28,087Change in estimated future development costs











(63,830
)


(25,759
)Accretion of discount


9,909




1,030



10,283



9,947Change in timing and other











(3,345
)


1,335Purchases of
    minerals-in-place


132,127












Net change in standardized measure


171,623




8,020



(41,021
)


3,359Standardized measure balance, beginning of period







61,806



102,827



99,468Standardized 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)ASSETSCurrent assets:Cash and cash equivalents

$
1,956


$
53,984Accounts receivable  trade


21,841



7,215Prepaid expenses


438



223Derivatives


2,615



3,075Total current assets


26,850



64,497Oil and natural gas properties  successful efforts
    method of accounting:Proved properties


677,439



209,723Unproved properties


35,046



34,569Accumulated depletion, depreciation, and amortization


(12,759
)


(1,946
)Total oil and natural gas properties, net


699,726



242,346Other property and equipment, net


226



184Acquisition deposits






47,500Derivatives


5,726



5,655Other


3,278



1,650Total assets

$
735,806


$
361,832LIABILITIES AND MEMBERS EQUITYCurrent liabilities:Accounts payable

$
2,629


$
786Accrued liabilities:Lease operating


3,541



1,667Development capital


8,922



10,565Production taxes, transportation, and marketing


1,367



748Derivatives


4,882



1,044Current portion of firm transportation contract liability


2,471



2,464Oil and natural gas revenues payable


723



1,832Other


5,736



2,576Total current liabilities


30,271



21,682Long-term debt


233,000



52,000Derivatives


6,834



1,990Asset retirement obligations, net of current portion


9,599



1,496Firm transportation contract liability, net of current portion


10,844



10,700Other


115



25Total liabilities


290,663



87,893Commitments and contingenciesMembers equity:Class A, 464,860,000 and 282,160,500 units issued and
    outstanding, respectively


445,143



273,939Class B, 96,500 and 96,000 units issued and
    outstanding, respectively






Total members equity


445,143



273,939Total liabilities and members equity

$
735,806


$
361,832  
 
 
 
   
 ENDURO F-19




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC



UNAUDITED
    CONSOLIDATED STATEMENTS OF OPERATIONS  
 Three


March 3, 2010Months


(Inception)Ended


ThroughMarch 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



77Derivative fair value loss


11,449



Other operating


896



Total expenses


33,261



77Operating 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



  
 
   
 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


$
273,939Contributions from members


182,699,500







182,699Issuance of Class B units






500



Net loss










(11,495
)Balance at March 31, 2011


464,860,000



96,500


$
445,143  
 
   
 ENDURO F-21




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC



UNAUDITED
    CONSOLIDATED STATEMENTS OF CASH FLOWS Three


March 3,Months


2010Ended


(Inception)March 31,


Through2011


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
)


77Net 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



100Proceeds from long-term debt borrowings


181,000



Payment of deferred loan costs


(1,497
)


Net cash provided by financing activities


362,202



100Net increase (decrease) in cash and cash equivalents


(52,028
)


100Cash and cash equivalents, beginning of period


53,984



Cash and cash equivalents, end of period

$
1,956


$
100  
 
   
 ENDURO F-22




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC



NOTES TO
    UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS  1.
    Organization and
    Nature of Operations 
    Principles of
    Consolidation
       
 
  2.
    Acquisitions  Denbury
    Acquisition
 
   
   ENDURO F-23




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO
    UNAUDITED CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
 
    Oil and natural gas properties

$
245,245Other equipment


24Accounts receivable


4,950Total assets acquired


250,219Asset 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  
   
  Samson
    Acquisition
        Oil and natural gas properties

$
131,780Accounts receivable


2,780Total assets acquired


134,560Asset retirement obligations


(722
)Total liabilities assumed


(722
)Fair value of net assets acquired

$
133,838  
   
  ConocoPhillips
    Acquisition
   ENDURO F-24




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO
    UNAUDITED CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
 
 
   
    Oil and natural gas properties

$
321,520Asset retirement obligations


(7,357
)Fair value of net assets acquired

$
314,163  
   
 
  Pro Forma
    Information
 
 
   
  
 Three Months EndedMarch 31,2011


2010(In thousands, except per unit amounts)Pro forma total revenues

$
33,793


$
20,127Pro forma net income (loss)

$
(9,559
)

$
1,441Pro forma net income (loss) per unit:Basic

$
(0.02
)

$
Diluted

$
(0.02
)

$
  
  3.
    Disclosures About
    Fair Value Measurements    
    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 ENDURO F-25




---



##### Table of Contents



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.        
 Fair Value Measurements at Reporting Date UsingQuoted Pricesin Active


SignificantFair Value


Markets for


Other


Significantas of


Identical


Observable


UnobservableMarch 31,


Assets


Inputs


Inputs2011


(Level 1)


(Level 2)


(Level 3)Oil and natural gas derivative contracts  assets

$
8,341


$



$
182


$
8,159Oil and natural gas derivative contracts  liabilities


11,716







6,327



5,389  
    
 Derivative Contracts Floors and CapsOil


Natural GasBalance at December 31, 2010

$
2,997


$
4,884Purchases






2,750Settlements


47



(295
)Unrealized gains (losses) included in earnings


(6,749
)


(864
)Balance at March 31, 2011

$
(3,705
)

$
6,475  
 ENDURO F-26




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO
    UNAUDITED CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
 
    December 31, 2010


March 31, 2011Carrying


Fair


Carrying


FairValue


Value


Value


ValueFinancial assets:Natural gas commodity contracts  current asset

$
1,639


$
1,639


$
2,087


$
2,087Oil commodity contracts  current asset


1,436



1,436



528



528Natural gas commodity contracts  long-term asset


3,386



3,386



4,776



4,776Oil commodity contracts  long-term asset


2,269



2,269



950



950Financial liabilities:Natural gas commodity contracts  current liabilities


333



333



768



768Oil commodity contracts  current liabilities


711



711



4,114



4,114Natural gas commodity contracts  long-term liabilities


1,120



1,120



1,016



1,016Oil commodity contracts  long-term liabilities


870



870



5,818



5,818Long-term debt


52,000



52,000



233,000



233,000     Long-Term
    Debt
    4.
    Derivative
    Financial Instruments 
   
 ENDURO F-27




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO
    UNAUDITED CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
 
    
 Daily Put


Average


Daily Swap


Average


Fair Value as ofPeriod

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



976January 2012  December 2012


14,000


$
4.90



10,000


$
4.57



2,072January 2013  December 2013


12,000


$
4.90



8,000


$
5.00



2,031$
5,079  
    
 Fair ValueDaily


Average


Daily


Average


Average


Daily





as ofPut


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
)  
 
 
    
 Fair ValueAverage


Average


Average


as ofDaily


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     ENDURO F-28




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO
    UNAUDITED CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
 
              
    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; 
  
    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.      60-month
 ENDURO F-29




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO
    UNAUDITED CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
 
  6.
    Asset Retirement
    Obligations    Asset retirement obligations  December 31, 2010

$
2,560Liabilities assumed at acquisition


8,079Accretion of discount


141Asset retirement obligations  March 31, 2011

$
10,780  
   
  7.
    Members
    Equity          8.
    Commitments and
    Contingencies  General
   ENDURO F-30




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO
    UNAUDITED CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
 
      Litigation
    9.
    Subsequent
    Events    
 Daily


Average





Average


Average


Average


DailyPut


Put


Daily


Sub-Floor


Floor


Cap


Swap


AverageVolumes


Price


Volumes


Price


Price


Price


Volumes


PricePeriod

(Bbls)


($/Bbl)


(Bbls)


($/Bbl)


($/Bbl)


($/Bbl)


(Bbls)


($/Bbl)2011


500


$
92.00



500


$
67.50


$
90.00


$
110.00



530


$
102.962012


500


$
92.00



500


$
67.50


$
90.00


$
110.00



520


$
104.102013





$




500


$
67.50


$
90.00


$
110.00



510


$
102.97  
 
   
 ENDURO F-31




---



##### Table of Contents



Report of
    Independent Registered Public Accounting Firm           
    ENDURO F-32




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC



CONSOLIDATED BALANCE SHEET  
 December 31,2010(In thousands,except unitamounts)ASSETSCurrent assets:Cash and cash equivalents

$
53,984Accounts receivable  trade


7,215Prepaid expenses


223Derivatives


3,075Total current assets


64,497Oil and natural gas properties  successful efforts
    method of accounting:Proved properties


209,723Unproved properties


34,569Accumulated depletion, depreciation, and amortization


(1,946
)Total oil and natural gas properties, net


242,346Other property and equipment, net


184Acquisition deposits


47,500Derivatives


5,655Other


1,650Total assets

$
361,832LIABILITIES AND MEMBERS EQUITYCurrent liabilities:Accounts payable

$
786Accrued liabilities:Lease operating


1,667Development capital


10,565Production taxes, transportation, and marketing


748Derivatives


1,044Current portion of firm transportation contract liability


2,464Oil and natural gas revenues payable


1,832Other


2,576Total current liabilities


21,682Long-term debt


52,000Derivatives


1,990Asset retirement obligations, net of current portion


1,496Firm transportation contract liability, net of current portion
    and other


10,725Total liabilities


87,893Commitments and contingenciesMembers equity:Class A, 282,160,500 units issued and outstanding


273,939Class B, 96,000 units issued and outstanding


Total members equity


273,939Total liabilities and members equity

$
361,832  
   ENDURO F-33




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC



CONSOLIDATED STATEMENT OF OPERATIONS  March 3, 2010(Inception)ThroughDecember 31,2010(In thousands,except per unitamounts)Revenues:Oil

$
106Natural gas


3,486Marketing


383Total revenues


3,975Expenses:Lease operating


507Production, ad valorem, and severance taxes


170Gathering and transportation


206Depletion, depreciation, and amortization


1,973Marketing


372General and administrative


3,826Derivative fair value loss


4,977Other operating


18Total expenses


12,049Operating 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


140,780Diluted


140,780    ENDURO F-34




---



##### Table of Contents



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



282,161Issuance of Class B units


96,000



Net loss






(8,222
)Balance at December 31, 2010





$
273,939    ENDURO F-35




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC



CONSOLIDATED STATEMENT OF CASH FLOWS  March 3,2010(Inception)ThroughDecember 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


1,973Unrealized loss on derivatives


4,977Other non-cash items


45Changes in operating assets and liabilities:Accounts receivable


(4,066
)Prepaid expenses


(223
)Derivative assets


(10,673
)Accounts payable and other accrued expenses


3,112Net 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


282,161Proceeds from long-term debt borrowings


52,000Payment of deferred loan costs


(1,678
)Net cash provided by financing activities


332,483Net increase in cash and cash equivalents


53,984Cash and cash equivalents, beginning of period


Cash and cash equivalents, end of period

$
53,984Supplemental cash flow information:Cash paid during the period for interest

$
134Non-cash investing and financing activities:Properties acquired, other than for cash

$
83    ENDURO F-36




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  1.
    Organization and
    Nature of Operations    2.
    Summary of
    Significant Accounting Policies  Principles of
    Consolidation
    Use of
    Estimates
      Cash
    Equivalents
    Accounts
    Receivable
    Oil and
    Natural Gas Properties
   ENDURO F-37




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
          unit-of-production
      project-by-project
  Other Property
    and Equipment
    Asset
    Retirement Obligations
   ENDURO F-38




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
      Revenue
    Recognition
            Income
    Taxes
    Derivatives
     ENDURO F-39




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    Segments
    Recently
    Issued Accounting Pronouncements
      3.
    Acquisition     ENDURO F-40




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    Oil and natural gas properties

$
241,634Other equipment


24Accounts receivable


4,950Total assets acquired


246,608Asset 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  
   
  Unaudited Pro
    Forma Acquisition Information
    Pro forma revenues

$
44,186Pro forma net loss


(3,467
)   4.
    Disclosures About
    Fair Value Measurements    
    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.   ENDURO F-41




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
      Fair Value Measurements at Reporting Date UsingQuoted Prices in

SignificantActive Markets

Other

SignificantFair Value at

for Identical

Observable

UnobservableDecember 31,

Assets

Inputs

Inputs2010

(Level 1)

(Level 2)

(Level 3)Oil and natural gas derivative contracts  assets

$
8,730


$



$
143


$
8,587Oil and natural gas derivative contracts  liabilities


3,034







2,328



706     Derivative Contracts  Floorsand CapsOil


Natural GasBalance at Inception

$



$
Purchases


4,713



5,960Unrealized losses included in earnings


(1,716
)


(1,076
)Balance at December 31, 2010

$
2,997


$
4,884     Carrying Value


Fair ValueFinancial assets:Natural gas commodity contracts  current asset

$
1,639


$
1,639Oil commodity contracts  current asset


1,436



1,436Natural gas commodity contracts  long-term asset


3,386



3,386Oil commodity contracts  long-term asset


2,269



2,269Financial liabilities:Natural gas commodity contracts  current liabilities


333



333Oil commodity contracts  current liabilities


711



711Natural gas commodity contracts  long-term liabilities


1,120



1,120Oil commodity contracts  long-term liabilities


870



870Long-term debt


52,000



52,000  ENDURO F-42




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    Long-Term
    Debt
    Assets and
    Liabilities Measured at Fair Value on a Nonrecurring
    Basis
        Concentrations
    of Credit Risk
   ENDURO F-43




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    Counterparty

Assets


LiabilitiesCredit Agricole

$
929


$
1,040BNP Paribas


2,675



661Bank of America Merrill Lynch


5,126



1,333Total

$
8,730


$
3,034   5.
    Derivative
    Financial Instruments      Fair Value atDaily 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


$
190March 2011  December 2011


13,000


$
4.18



10,000


$
4.30



1,116January 2012  December 2012


13,000


$
4.92



10,000


$
4.57



1,875January 2013  December 2013


2,000


$
4.95



5,000


$
5.10



391$
3,572     Average


AverageDaily


Average


Daily


Collar


Collar


Daily





Fair Value atPut


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


$
744March 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



1,466January 2013  December 2013





$




160


$
82.00


$
95.60



150


$
90.00



(337
)$
1,478  ENDURO F-44




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    Average


Average


Average


Fair Value atDaily


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


$
376January 2012  December 2012


500


$
67.50


$
90.00


$
110.00



212January 2013  December 2013


500


$
67.50


$
90.00


$
110.00



58$
646   6.
    Long-Term
    Debt              
    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; ENDURO F-45




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
 
   
    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.      60-month
  7.
    Asset Retirement
    Obligations    Asset retirement obligations at March 3, 2010 (Inception)

$
Liabilities assumed at acquisition


2,542Accretion of discount


18Asset retirement obligations at December 31, 2010

$
2,560     8.
    Members
    Equity       ENDURO F-46




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
      9.
    Commitments and
    Contingencies  General
      Litigation
    Lease
    Agreements
    2011

$
2872012


4172013


4432014


7332015


685Thereafter


507$
3,072  ENDURO F-47




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  Firm
    Transportation Agreement
 
  10-year
 
    2011

$
2,4642012


2,4702013


2,4642014


2,4642015


2,464Thereafter


10,059$
22,385   10.
    Major
    Customers    11.
    Related-Party
    Transactions    12.
    Subsequent
    Events     ENDURO F-48




---



##### Table of Contents



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 ThroughDecember 31, 2010(In thousands)Proved acquisitions

$
207,123Unproved acquisitions


34,569Total acquisitions


241,692Development costs


2,600Total costs incurred

$
244,292   Reserve
    Quantity Information
    12-month
   ENDURO F-49




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    Inception through December 31, 2010Oil


Natural Gas


Total(MBbls)


(MMcf)


(MBOE)Total proved reservesBalance as of March 3, 2010 (Inception)










Purchases of
    minerals-in-place


27



99,289



16,575Production


(1
)


(853
)


(143
)Balance as of December 31, 2010


26



98,436



16,432Total proved developed reservesBalance as of March 3, 2010 (Inception)










Balance as of December 31, 2010


26



63,848



10,667Proved undeveloped reservesBalance as of March 3, 2010 (Inception)










Balance as of December 31, 2010






34,588



5,765   Standardized
    Measure of Discounted Future Net Cash Flows
        Oil and natural gas producing activities:Future cash inflows

$
394,848Future production costs


(98,627
)Future development costs


(55,634
)Undiscounted future net cash flows


240,58710% annual discount factor


(113,190
)Standardized measure of discounted future cash flows

$
127,397  ENDURO F-50




---



##### Table of Contents



ENDURO RESOURCE
    PARTNERS LLC
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    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


2,600Purchases of
    minerals-in-place


127,506Standardized measure balance as of December 31, 2010

$
127,397  ENDURO F-51




---



##### Table of Contents



ENDURO SPONSOR
  UNAUDITED
    PRO FORMA FINANCIAL STATEMENTS
 
  Introduction
 
 
   
 
   
 
   
 ENDURO F-52




---



##### Table of Contents



ENDURO
    SPONSOR
 
 
 UNAUDITED PRO
    FORMA BALANCE SHEET(in
    thousands)   
 March 31, 2011Offering


Pro FormaHistorical


Adjustments


As AdjustedAssetsCurrent assets:Cash and cash equivalents

$
1,956


$
87,000
(b)

$
88,956Accounts receivable  trade


21,841







21,841Prepaid expenses


438







438Derivatives


2,615







2,615Total current assets


26,850



87,000



113,850Oil and natural gas properties  successful efforts
    method of accounting:Proved properties


677,439



(216,275
)(c)


461,164Unproved properties


35,046







35,046Accumulated depletion, depreciation, and amortization


(12,759
)


3,804
(c)


(8,955
)Total oil and natural gas properties, net


699,726



(212,471
)(c)


487,255Other property and equipment, net


226







226Derivatives


5,726







5,726Other


3,278







3,278Total assets

$
735,806


$
(125,471
)

$
610,335Liabilities and members equityCurrent liabilities:Accounts payable

$
2,629


$



$
2,629Accrued liabilities:Lease operating


3,541







3,541Development capital


8,922







8,922Production taxes, transportation, and marketing


1,367







1,367Derivatives


4,882







4,882Current portion of firm transportation contract liability


2,471







2,471Oil and natural gas revenues payable


723







723Other


5,736







5,736Total current liabilities


30,271







30,271Long-term debt


233,000



(233,000
)(b)


Derivatives


6,834







6,834Asset retirement obligations, net of current portion


9,599







9,599Firm transportation contract liability, net of current portion


10,844







10,844Other


115







115Total liabilities


290,663



(233,000
)


57,663Members equity:Class A, 464,860,000 units issued and outstanding


445,143



107,529
(d)


552,672Class B, 96,500 units issued and outstanding










Total members equity


445,143



107,529



552,672Total liabilities and members equity

$
735,806


$
(125,471
)

$
610,335  
 
   
 ENDURO F-53




---



##### Table of Contents



ENDURO
    SPONSOR
 
 
 UNAUDITED PRO
    FORMA STATEMENT OF OPERATIONS





(in thousands)  
 Three Months Ended March 31, 2011ConocoPhillips


Pro Forma AfterEnduro


Permian Basin


Acquisition


Offering


Pro Forma AsSponsor


Assets(a)


Adjustments


Adjustments


AdjustedRevenues:Oil

$
10,236


$
9,966


$
20,202


$
(1,949
)

$
18,253Natural gas


11,899



875



12,774



(702
)


12,072Marketing


817







817







817Total revenues


22,952



10,841



33,793



(2,651
)(h)


31,142Expenses:Lease operating


4,007



2,820



6,827







6,827Production, ad valorem, and severance taxes


1,447



883



2,330







2,330Gathering and transportation


794



41



835







835Depletion, depreciation, and amortization


10,830



3,963
(e)


14,793



(4,545
)(i)


10,248Marketing


795







795







795General and administrative


3,043



463
(f)


3,506







3,506Derivative fair value loss


11,449







11,449







11,449Other operating


896



137
(g)


1,033







1,033Total expenses


33,261



8,307



41,568



(4,545
)


37,023Operating income (loss)


(10,309
)


2,534



(7,775
)


1,894



(5,881
)Interest expense, net


(1,220
)


(598
)(k)


(1,818
)


1,818
(j)


Income (loss) before income taxes


(11,529
)


1,936



(9,593
)


3,712



(5,881
)Deferred income tax benefit


34







34







34Net income (loss)

$
(11,495
)

$
1,936


$
(9,559
)

$
3,712


$
(5,847
)  
 
   
 ENDURO F-54




---



##### Table of Contents



ENDURO
    SPONSOR
 
 
 UNAUDITED PRO
    FORMA STATEMENT OF OPERATIONS(in
    thousands) Year Ended December 31, 2010Enduro



Predecessor -



Predecessor -Sponsor



DNR



EACInception



March 9



January 1


Acquisition Adjustments


Pro FormaThrough



Through



Through


Samson


ConocoPhillips


Other


Total


AfterDecember 31,



November 30,



March 8,


Permian Basin


Permian Basin


Acquisition


Acquisition


Acquisition


Offering


Pro Forma As2010



2010



2010


Assets(a)


Assets(a)


Adjustments


Adjustments


Adjustments


Adjustments


AdjustedRevenues:Oil

$
106



$
1,036



$
331


$
16,626


$
52,062


$



$
68,688


$
70,161


$
(8,678
)

$
61,483Natural gas


3,486




35,503




10,756



5,650



7,025







12,675



62,420



(4,186
)


58,234Marketing


383




3,671




1,077



















5,131







5,131Total revenues


3,975




40,210




12,164



22,276



59,087







81,363



137,712



(12,864
)(h)


124,848Expenses:Lease operating


507




5,285




1,142



3,428



16,657







20,085



27,019







27,019Production, ad valorem, and severance taxes


170




2,003




548



1,702



4,994







6,696



9,417







9,417Gathering and transportation


206




2,755




429



212



243







455



3,845







3,845Depletion, depreciation, and amortization


1,973




21,754




7,949



10,694
(e)


24,877
(e)


(29,703
)(e)


33,047



64,723



(19,228
)(i)


45,49527,179
(e)Exploration expense







9,957




231



















10,188







10,188Marketing


372




3,588




1,060



















5,020







5,020General and administrative


3,826




1,254




2,481



1,273
(f)


2,908
(f)






4,181



11,742







11,742Merger-related transaction costs







6,922




16,136











(23,058
)(k)


(23,058
)










Derivative fair value loss


4,977





























4,977







4,977Other operating


18




24




9



86
(g)


823
(g)



(g)


909



960







960Total expenses


12,049




53,542




29,985



17,395



50,502



(25,582
)


42,315



137,891



(19,228
)


118,663Operating income (loss)


(8,074
)



(13,332
)



(17,821
)


4,881



8,585



25,582



39,048



(179
)


6,364



6,185Interest expense, net


(148
)



(6,183
)







(1,796
)(j)


(4,768
)(j)


6,183
(j)


(2,135
)


(8,466
)


8,466
(j)


(1,754
)(j)Net income (loss)

$
(8,222
)


$
(19,515
)


$
(17,821
)

$
3,085


$
3,817


$
30,011


$
36,913


$
(8,645
)

$
14,830


$
6,185  
 
   
 ENDURO F-55




---



##### Table of Contents



ENDURO SPONSOR



NOTES TO
    UNAUDITED PRO FORMA FINANCIAL STATEMENTS  1.
    Basis of
    Presentation 
 
   
 
   
 
   
 
   
 
  2.
    Pro Forma
    Adjustments 
 
   
 
   
 
   
 
   
  
 (b
)

Gross cash proceeds from the sale of trust units

$
350,000Repayment of outstanding borrowings on revolving credit facility


(233,000
)Payment of underwriting discount, structuring fee and other
    offering expenses


(30,000
)$
87,000 
 ENDURO F-56




---



##### Table of Contents



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

$
550,925Less: Asset retirement obligations


(10,237
)Property to be conveyed to the Trust


540,688Multiplied by percentage allocable to Net Profits Interest


80
%Historical cost of oil and natural gas properties to be conveyed
    to the Trust


432,550Multiplied by Enduro Sponsors retained interest


50
%Reduction of oil and natural gas proved properties due to
    conveyance of Net Profits Interest to the Trust

$
216,275Accumulated 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 Enduro Sponsors retained interest


50
%Reduction of accumulated depletion, depreciation, and
    amortization due to conveyance of Net Profits Interest to the
    Trust

$
(3,804
)(d
)

Gain on sale of Net Profits Interest calculated as follows:Gross cash proceeds from the sale of trust units

$
350,000Less: Net book value of conveyed Net Profits Interest


(424,942
)Plus: Enduro Sponsor retained interest in trust units


212,471Payment of underwriting discounts, structuring fees and other
    offering expenses


(30,000
)Gain on sale of units

$
107,529  
 
   
 
   
 
   
 
   
 ENDURO F-57




---



##### Table of Contents



ENDURO SPONSOR
  NOTES TO
    UNAUDITED PRO FORMA FINANCIAL
    STATEMENTS  (Continued)
 
 
   
 
   
  
 Three Months


Year EndedEnded March 31,


December 31,2011


2010(h)

Calculation of net profits:Revenues of the Underlying Properties Oil

$
20,150


$
70,033Natural gas


7,262



33,787Total revenues


27,412



103,820Direct operating expenses of the Underlying Properties Lease operating


6,185



24,579Gathering and processing


489



1,977Production and other taxes


2,005



8,069Total direct operating expenses


8,679



34,625Development costs


12,105



37,036Total expenses and development costs


20,784



71,661Net profits


6,628



32,159Multiplied by percentage allocable to Net Profits Interest


80
%


80
%Net profits to Trust from Net Profits Interest


5,302



25,727Multiplied by Enduro Sponsors retained interest


50
%


50
%Reduction in Enduro Sponsors total revenues due to Net Profits Interest of public unitholders

$
2,651


$
12,864  
 
   
  
 Three Months


Year EndedEnded March 31,


December 31,2011


2010(i)

Reduce depreciation on assets conveyed to Trust

$
(4,545
)

$
(19,228
)  
 
   
 
   
 ENDURO F-58




---



##### Table of Contents



Cawley,
    Gillespie & Associates, Inc.
  PETROLEUM
    CONSULTANTS
  9601 AMBERGLEN BLVD., SUITE 117

306 WEST SEVENTH STREET, SUITE 302

1000 LOUISIANA STREET, SUITE 625AUSTIN, TEXAS
    78729-1106

FORT WORTH, TEXAS 76102-4987

HOUSTON, TEXAS 77002-5008512-249-7000

817-336-2461

713-651-9944www.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 SummaryEnduro Resource Partners LLC InterestsTotal Proved ReservesTexas and Louisiana PropertiesAs of December 31, 2010Pursuant to the Guidelines of theSecurities and Exchange Commission forReporting Corporate Reserves andFuture 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:
  ProvedProved


DevelopedDeveloped


Non-


Proved


TotalProducing


Producing


Undeveloped


ProvedNet ReservesOil

- Mbbl


25.6



0.0



0.0



25.6Gas

- MMcf


53,065.5



10,782.2



34,588.2



98,435.9RevenueOil

- M

$
1,974.7



0.0



0.0



1,974.7Gas

- M

$
211,574.7



40,971.5



140,327.7



392,873.9Severance Taxes

- M

$
7,760.1



862.9



3,225.3



11,848.3Ad Valorem Taxes

- M

$
4,312.9



802.2



2,742.0



7,857.1Operating Expenses

- M

$
55,531.1



4,619.7



12,032.0



72,182.8Investments

- M

$
0.0



3,738.2



51,896.0



55,634.2Net Operating Income (BFIT)

- M

$
145,945.3



30,948.6



70,432.3



247,326.2Discounted 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




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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 COPASare 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




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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 A-1-6




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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 A-1-7




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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 A-1-8




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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 A-1-9




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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.
 ANNEX A-1-10




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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 A-1-11




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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 625AUSTIN, TEXAS
    78729-1106

FORT WORTH, TEXAS 76102-4987

HOUSTON, TEXAS 77002-5008512-249-7000

817-336-2461

713-651-9944www.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 SummaryEnduro Resource Partners LLC InterestsPro Forma Samson Non-Operated Acquisition ofPermian Properties by Enduro Resource PartnersUsing Yearend SEC Prices as of December 31, 2010Proved Developed Producing ReservesTexas and New Mexico PropertiesAs of December 31, 2010Pursuant 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.
 ANNEX A-2-1




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The proved
    reserves and economics by category are summarized as follows:
  ProvedDevelopedProducingNet ReservesOil

- Mbbl


3,047.8Gas

- MMcf


10,780.7RevenueOil

- M$


237,652.0Gas

- M$


54,600.6Severance Taxes

- M$


17,159.8Ad Valorem Taxes

- M$


7,301.9Operating Expenses

- M$


82,910.5Net Operating Income (BFIT)

- M$


184,880.4Discounted 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.
 
 ANNEX A-2-2




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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.
 ANNEX A-2-3




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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
 ANNEX A-2-4




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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)

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 COPASare 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.  ANNEX A-2-6




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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 A-2-7




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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 A-2-8




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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 A-2-9




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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.
 ANNEX A-2-10




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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 A-2-11




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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 625AUSTIN, TEXAS
    78729-1106

FORT WORTH, TEXAS 76102-4987

HOUSTON, TEXAS 77002-5008512-249-7000

817-336-2461

713-651-9944www.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 SummaryEnduro Resource Partners LLC InterestsPro Forma Conoco Phillips Acquisition of 
      Permian Properties by Enduro Resource Partners
      Using Yearend SEC Prices as of December 31, 2010Total Proved ReservesTexas and New Mexico PropertiesAs of December 31, 2010Pursuant 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.
 ANNEX A-3-1




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The proved
    reserves and economics by category are summarized as follows:
  ProvedDeveloped


Proved


TotalProducing


Undeveloped


ProvedNet ReservesOil

- Mbbl


9,131.2



379.2



9,510.4Gas

- MMcf


9,406.4



1,293.4



10,699.8NGL




182.7



0.0



182.7RevenueOil

- M$


692,325.1



28,715.3



721,040.4Gas

- M$


51,748.6



7,496.6



59,245.2NGL




8,536.6



0.0



8,536.6Severance Taxes

- M$


41,604.2



1,883.1



43,487.3Ad Valorem Taxes

- M$


21,520.4



1,201.5



22,721.9Operating Expenses

- M$


335,279.8



5,721.4



341,001.1Other Deductions

- M$


719.8



44.3



764.1Investments

- M$


0.0



6,000.0



6,000.0Net Operating Income (BFIT)

- M$


353,486.3



21,361.5



374,847.8Discounted 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.
 ANNEX A-3-2




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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.
 ANNEX A-3-3




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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
 ANNEX A-3-4




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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)

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 COPASare 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-3-5




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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 A-3-6




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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 A-3-7




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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 A-3-8




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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 A-3-9




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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.
 ANNEX A-3-10




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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 A-3-11




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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 625AUSTIN, TEXAS
    78729-1106

FORT WORTH, TEXAS
    76102-4987

HOUSTON, TEXAS
    77002-5008512-249-7000

817-336-2461

713-651-9944www.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 theEnduro Resource Partners LLC Interests

Securities and Exchange Commission forTotal Proved Reserves for the Underlying Properties

Reporting Corporate Reserves andof Enduro Royalty Trust Total Controlled Interests

Future Net RevenueTexas, Louisiana and New Mexico PropertiesUsing 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.
  ProvedProved


DevelopedDeveloped


Non-


Proved


TotalProducing


Producing


Undeveloped


ProvedNet ReservesOil

- Mbbl


12,204.3



0.0



379.2



12,583.6Gas

- MMcf


48,494.9



2,798.0



34,494.5



85,787.4NGL

- Mbbl


182.7



0.0



0.0



182.7RevenueOil

- M$


931,928.0



0.0



28,715.3



960,643.3Gas

- M$


221,463.6



11,360.0



142,714.5



375,538.1NGL

- M$


8,536.6



0.0



0.0



8,536.6Severance Taxes

- M$


63,314.4



229.1



4,997.1



68,540.5Ad Valorem Taxes

- M$


31,269.6



222.6



3,843.6



35,335.8Operating Expenses

- M$


455,929.7



944.1



17,263.6



474,137.3Investments

- M$


0.0



2,429.9



55,243.9



57,673.7Net Operating Income (BFIT)

- M$


611,414.5



7,534.4



90,081.7



709,030.5Discounted at 10%

- M$


313,925.7



4,401.8



31,204.4



349,531.9  ANNEX B-1




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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




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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




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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




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##### 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 COPASare 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




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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 B-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 B-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 B-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 B-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.
 ANNEX B-10




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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 B-11




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Cawley,
    Gillespie & Associates, Inc.
  PETROLEUM
    CONSULTANTS
  9601 AMBERGLEN BLVD., SUITE 117 AUSTIN, TEXAS
    78729-1106512-249-7000

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.
  ProvedProved

DevelopedDeveloped

Non-

Proved

TotalProducing

Producing

Undeveloped

ProvedNet ReservesOil

− Mbbl


5,352.0



0.0



190.0



5,541.8Gas

− MMcf


26,153.6



1,554.0



15,314.9



43,058.0NGL

− Mbbl


100.6



0.0



0.0



100.6RevenueOil

− M$


408,630.2



0.0



14,384.5



423,014.7Gas

− M$


119,425.4



6,309.4



62,638.7



188,373.4NGL

− M$


4,702.8



0.0



0.0



4,702.8Severance Taxes

− M$


29,593.6



160.4



3,168.4



32,922.4Ad Valorem Taxes

− M$


14,049.6



123.0



1,799.6



15,972.2Operating Expenses

− M$


0.0



0.0



0.0



0.0Investments

− M$


0.0



0.0



0.0



0.0Net Operating Income (BFIT)

− M$


489,115.2



6,026.0



72,055.1



567,196.3Discounted at 10%

− M$


251,206.7



3,520.5



24,960.5



279,687.7  ANNEX C-1




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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




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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




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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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##### 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 COPASare 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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##### 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 C-6




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##### 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 C-7




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##### 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 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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##### 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 C-10




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##### 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 C-11




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##### Table of Contents



[          ] Trust Units
 
  
    Prospectus
 ,
    2011
    Barclays Capital
 
 Citi
 
 
 Goldman, Sachs &
    Co.
 
 
 RBC Capital Markets
 
 
 Wells Fargo
    Securities




---



##### Table of Contents



PART II
  INFORMATION NOT
    REQUIRED IN PROSPECTUS
  Item 13.
    Other Expenses
    of Issuance and Distribution.    Registration fee

$
43,538FINRA filing fee


38,000NYSE listing fee


*Printing and engraving expenses


*Fees and expenses of legal counsel


*Accounting fees and expenses


*Transfer agent and registrar fees


*Trustee fees and expenses


*Miscellaneous


*Total

$
*     *
    
    To be provided by amendment  Item 14.
    Indemnification
    of Directors and Officers.    Section 18-108
   II-1




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##### Table of Contents



Item 15
    Recent Sales
    of Unregistered Securities.    Item 16.
    Exhibits and
    Financial Statement Schedules.  Exhibits.
    
 ExhibitNumber



Description1
.1**



Form of Underwriting Agreement.3
.1



Certificate of Formation of Enduro Resource Partners LLC.3
.2**



Amended & Restated Limited Liability Company Agreement of
    Enduro Resource Partners LLC.3
.3



Certificate of Trust of Enduro Royalty Trust.3
.4



Trust Agreement.3
.5**



Form of Second 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.  Financial Statement Schedules.
    Item 17.
    Undertakings.     II-2




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##### Table of Contents



Form 10-K
 II-3




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##### Table of Contents



SIGNATURES
 
   
  Enduro Resource Partners LLC
  By:
    /s/  Jon
    S. Brumley    
   
  
 Signature

Title/s/  Jon
    S. BrumleyJon
    S. Brumley

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

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

Manager*David
    Leuschen

Manager*Pierre
    F. Lapeyre, Jr.

Manager*N.
    John Lancaster

Manager*I.
    Jon Brumley

Manager*By:

/s/  Jon
    S. BrumleyJon
    S. Brumley
    Attorney-in-Fact  
 II-4




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##### Table of Contents



SIGNATURES
 
   
  Enduro Royalty Trust
  By: Enduro Resource Partners LLC
  By:
    /s/  Jon
    S. Brumley    II-5




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##### Table of Contents



INDEX TO
    EXHIBITS
  
 ExhibitNumber



Description1
.1**



Form of Underwriting Agreement.3
.1



Certificate of Formation of Enduro Resource Partners LLC.3
.2**



Amended & Restated Limited Liability Company Agreement of
    Enduro Resource Partners LLC.3
.3



Certificate of Trust of Enduro Royalty Trust.3
.4



Trust Agreement.3
.5**



Form of Second 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.