##### Table of Contents





As filed with the Securities and Exchange
    Commission on June 23, 2011
  Registration
    No. 333-
     UNITED STATES SECURITIES AND
    EXCHANGE COMMISSIONWashington, D.C.
    20549
 Form S-1
 REGISTRATION STATEMENT
    UNDER
    THE SECURITIES ACT OF 1933
      MEMORIAL PRODUCTION PARTNERS
    LP
 (Exact name of registrant as
    specified in its charter)
  Delaware(State or other jurisdiction
    of
    incorporation or organization)

1311(Primary Standard
    Industrial
    Classification Code Number)

90-0726667(IRS Employer
    Identification Number)   1401 McKinney, Suite 1025
    Houston, Texas 77010(713) 579-5700 (Address, including zip
    code, and telephone number, including area code, of
    registrants principal executive offices)
  John A. Weinzierl
    President, Chief Executive Officer and Chairman
    Memorial Production Partners GP LLC
    1401 McKinney, Suite 1025
    Houston, Texas 77010(713) 579-5700 (Name, address, including
    zip code, and telephone number, including area code, of agent
    for service)
  Copies to:
  John Goodgame
    Akin Gump Strauss Hauer & Feld LLP
    1111 Louisiana Street, 44th Floor
    Houston, Texas 77002(713) 220-8144

Douglas E. McWilliams
    Jeffery K. Malonson
    Vinson & Elkins L.L.P.
    1001 Fannin, Suite 2500
    Houston, Texas 77002
    (713) 758-2222   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   CALCULATION
    OF REGISTRATION FEE
  Proposed Maximum


Amount ofTitle of Each Class of


Aggregate


RegistrationSecurities to be Registered


Offering Price(1)(2)


FeeCommon units representing limited partner interests


$287,500,000


$33,379   (1)
    
    Includes common units issuable upon exercise of the
    underwriters option to purchase additional common units.(2)
    
    Estimated solely for the purpose of calculating the registration
    fee pursuant to Rule 457(o).  The Registrant hereby amends this Registration Statement on
    such date or dates as may be necessary to delay its effective
    date until the Registrant shall file a further amendment which
    specifically states that this Registration Statement shall
    thereafter become effective in accordance with Section 8(a)
    of the Securities Act of 1933 or until the Registration
    Statement shall become effective on such date as the Securities
    and Exchange Commission, acting pursuant to said
    Section 8(a), may determine.




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##### Table of Contents



The
information in this preliminary 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 preliminary prospectus is not an
offer to sell nor does it seek an offer to buy these securities
in any jurisdiction where the offer or sale is not permitted.


SUBJECT TO COMPLETION DATED
    JUNE 23, 2011
  PRELIMINARY PROSPECTUS
  
 Memorial Production Partners
    LP
 Common Units
 Representing Limited Partner
    Interests
          Investing in our common units involves risks. Please read
    Risk Factors beginning on page 22.
    
    We may not have sufficient cash flow from operations to pay the
    minimum quarterly distribution on our common units following the
    establishment of cash reserves and payment of fees and expenses,
    including payments to our general partner.
    Our estimated oil and natural gas reserves will naturally
    decline over time, and we may be unable to sustain distributions
    at the level of our minimum quarterly distribution.
    Oil and natural gas prices are very volatile and a decline in
    oil or natural gas prices could cause us to reduce our
    distributions or cease paying distributions altogether.
    Our general partner and its affiliates own a controlling
    interest in us and will have conflicts of interest with, and owe
    limited fiduciary duties to, us.
    Memorial Resource, the Funds and other affiliates of our general
    partner will not be limited in their ability to compete
    with us.
    Neither we nor our general partner have any employees and we
    will rely solely on the employees of Memorial Resource to manage
    our business. The management team of Memorial Resource, which
    includes the individuals who will manage us, will also perform
    substantially similar services for itself and will own and
    operate its own assets, and thus will not be solely focused on
    our business.
    Our unitholders have limited voting rights and are not entitled
    to elect our general partner or its board of directors.
    Our unitholders will experience immediate and substantial
    dilution of $      per unit.
    Our tax treatment depends on our status as a partnership for
    federal income tax purposes.
    Our unitholders will be required to pay taxes on their share of
    our income even if they do not receive any cash distributions
    from us.  Neither the Securities and Exchange Commission nor any state
    securities commission has approved or disapproved of these
    securities or determined if this prospectus is truthful or
    complete. Any representation to the contrary is a criminal
    offense.
    Per Common Unit

TotalPublic offering price

$



$Underwriting discount(1)

$



$Proceeds, before expenses, to Memorial Production Partners LP

$



$     (1)
    
    Excludes a structuring fee equal
    to     % of the gross proceeds of this
    offering payable to Citigroup Global Markets Inc.          Citi

Raymond James

Wells Fargo Securities       J.P. Morgan




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##### Table of Contents





TABLE OF
    CONTENTS
   
 PageSummary


1Overview


1Our Properties


2Our Hedging Strategy


2Our Principal Business Relationships


3Our Relationship with Memorial Resource


3Our Relationship with Natural Gas Partners and
    the Funds


4Our Business Strategies


4Our Competitive Strengths


5Risk Factors


6Our Partnership Structure and Formation
    Transactions


7Background Information Regarding Our Predecessor
    and the Partnership Properties


8Our Ownership and Organizational Structure


9Principal Executive Offices and Internet
    Address


10Management of the Partnership


10Summary of Conflicts of Interest and Fiduciary
    Duties


10The Offering


12Summary Historical and Pro Forma Financial
    Data


16Non-GAAP Financial Measure


18Summary Reserve and Pro Forma Operating Data


20Risk Factors


22Risks Related to Our Business


22Risks Inherent in an Investment in Us


39Tax Risks to Unitholders


53Use of Proceeds


58Capitalization


59Dilution


60Our Cash Distribution Policy and Restrictions on
    Distributions


61General


61Our Minimum Quarterly Distribution


63Unaudited Pro Forma Available Cash for the Year
    Ended December 31, 2010 and Twelve Months Ended
    March 31, 2011


65Memorial Production Partners LP Unaudited Pro
    Forma Cash Available for Distribution


67Estimated Adjusted EBITDA for the Twelve Months
    Ending June 30, 2012


68Memorial Production Partners LP Estimated
    Adjusted EBITDA


71Assumptions and Considerations


72Sensitivity Analysis


80Provisions of Our Partnership Agreement Relating
    to Cash Distributions


84Distributions of Available Cash


84Operating Surplus and Capital Surplus


85Capital Expenditures


87Subordination Period


89Distributions of Available Cash from Operating
    Surplus During the Subordination Period


91 i




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PageDistributions of Available Cash from Operating
    Surplus After the Subordination Period


91General Partner Interest and Incentive
    Distribution Rights


91Percentage Allocations of Available Cash from
    Operating Surplus


92General Partners Right to Reset Incentive
    Distribution Levels


92Distributions from Capital Surplus


94Adjustment to the Minimum Quarterly Distribution
    and Target Distribution Levels


95Distributions of Cash Upon Liquidation


96Selected Historical and Pro Forma Financial
    Data


98Managements Discussion and Analysis of
    Financial Condition and Results of Operations


100Overview


100Historical and Pro Forma Financial and Operating
    Data


107Pro Forma Results of Operations


108Pro Forma Liquidity and Capital Resources


108Pro Forma Quantitative and Qualitative Disclosure
    About Market Risk


111Predecessor Results of Operations


112Predecessor Liquidity and Capital Resources


119Predecessor Quantitative and Qualitative
    Disclosure About Market Risk


122Critical Accounting Policies and Estimates


124Recently Issued Accounting Pronouncements


126Internal Controls and Procedures


127Inflation


128Off-Balance Sheet Arrangements


128Business and Properties


129Overview


129Our Properties


129Our Hedging Strategy


130Our Principal Business Relationships


130Our Business Strategies


132Our Competitive Strengths


134Properties


135Oil and Natural Gas Data and
    Operations  Properties


138Oil and Natural Gas Data and
    Operations  Our Predecessor


143Operations


144Environmental Matters and Regulation


146Other Regulation of the Oil and Natural Gas
    Industry


150Employees


151Offices


152Legal Proceedings


152Management


153Management of Memorial Production Partners LP


153Directors and Executive Officers


155Reimbursement of Expenses of Our General
    Partner


156Executive Compensation


156Compensation Discussion and Analysis


157 ii




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##### Table of Contents



PageDirector Compensation


159Long-Term Incentive Plan


159Relation of Compensation Policies and Practices
    to Risk Management


161Security Ownership Of Certain Beneficial Owners
    And Management


162Certain Relationships and Related Party
    Transactions


164Distributions and Payments to Our General Partner
    and Its Affiliates


164Amended and Restated Limited Liability Company
    Agreement of Memorial Production Partners GP LLC


165Agreements Governing the Transactions


165Review, Approval or Ratification of Transactions
    with Related Persons


166Conflicts of Interest and Fiduciary Duties


168Conflicts of Interest


168Fiduciary Duties


175Description of the Common Units


178The Units


178Transfer Agent and Registrar


178Transfer of Common Units


178The Partnership Agreement


180Organization and Duration


180Purpose


180Cash Distributions


180Capital Contributions


180Limited Voting Rights


181Applicable Law; Forum, Venue and Jurisdiction


182Limited Liability


182Issuance of Additional Securities


183Amendment of the Partnership Agreement


184Merger, Consolidation, Conversion, Sale or Other
    Disposition of Assets


186Termination and Dissolution


186Liquidation and Distribution of Proceeds


187Withdrawal or Removal of Our General Partner


187Transfer of General Partner Units


188Transfer of Incentive Distribution Rights


189Transfer of Ownership Interests in Our General
    Partner


189Change of Management Provisions


189Limited Call Right


189Meetings; Voting


189Status as Limited Partner


190Non-Citizen Assignees; Redemption


190Non-Taxpaying Assignees; Redemption


190Indemnification


191Reimbursement of Expenses


191Books and Reports


191Right to Inspect Our Books and Records


192 iii




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##### Table of Contents



PageRegistration Rights


192Units Eligible for Future Sale


193Material Tax Consequences


194Partnership Status


194Limited Partner Status


196Tax Consequences of Unit Ownership


196Tax Treatment of Operations


202Disposition of Common Units


206Uniformity of Units


209Tax-Exempt Organizations and Other Investors


209Administrative Matters


210State, Local and Other Tax Considerations


212Investment in Memorial Production Partners LP by
    Employee Benefit Plans


214Underwriting


216Notice to Prospective Investors in the European
    Economic Area


219Notice to Prospective Investors in the United
    Kingdom


219Notice to Prospective Investors in Germany


220Notice to Prospective Investors in the
    Netherlands


220Notice to Prospective Investors in Switzerland


220Validity of the Common Units


221Experts


221Where You Can Find More Information


221Forward-Looking Statements


222Index to Financial Statements


F-1Appendix A First Amended and Restated
    Agreement of Limited Partnership of Memorial Production Partners
    LP


A-1Appendix B Glossary of Terms


B-1Appendix C Netherland, Sewell &
    Associates, Inc. Summary of December 31, 2010 Reserves


C-1Appendix D Netherland, Sewell &
    Associates, Inc. Summary Reserve Report


D-1Appendix E Miller and Lents, Ltd. Summary of
    January 1, 2011 Reserves


E-1EX-3.1EX-3.2EX-3.4EX-3.5EX-21.1EX-23.1EX-23.2EX-23.3EX-23.4EX-23.5    You should rely only on the information contained in this
    prospectus. We have not, and the underwriters have not,
    authorized anyone to provide you with different information. If
    anyone provides you with different or inconsistent information,
    you should not rely on it. We are not, and the underwriters are
    not, making an offer to sell these securities in any
    jurisdiction where an offer or sale is not permitted. You should
    assume that the information appearing in this prospectus is
    accurate as of the date on the front cover of this prospectus
    only. Our business, financial condition, results of operations
    and prospects may have changed since that date.
     iv




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Industry
    and Market Data
    Commonly
    Used Defined Terms
    
    Memorial Production Partners, the
    partnership, we, our,
    us or like terms refer collectively to Memorial
    Production Partners LP and its subsidiaries;
    our general partner refers to Memorial Production
    Partners GP LLC, our general partner;
    our predecessor refers collectively to (a) BlueStone
    Natural Resources Holdings, LLC, (b) certain oil and natural gas
    properties owned by Classic Hydrocarbons Holdings, L.P., and (c)
    for periods after April 8, 2011, certain oil and natural
    gas properties owned by WHT Energy Partners LLC, a subsidiary of
    Memorial Resource that acquired those properties in April 2011,
    which are collectively our predecessor for accounting purposes
    and the owners, prior to the formation transactions, of the
    Partnership Properties;
    the Funds refers collectively to Natural Gas
    Partners VIII, L.P. and Natural Gas Partners IX, L.P.;
    Memorial Resource refers collectively to Memorial
    Resource Development LLC and its subsidiaries;
    Partnership Properties or our properties
    refers to the properties, producing wells, and related oil and
    natural gas interests to be contributed to us by our predecessor
    and certain other subsidiaries of Memorial Resource in
    connection with this offering;
    formation transactions refers to (i) the
    contribution by the Funds of their respective controlling
    ownership interests in certain of their subsidiaries (including
    our predecessor) to Memorial Resource prior to the closing of
    this offering and (ii) the contribution by Memorial
    Resource to us of the Partnership Properties at the closing of
    this offering, in each case including transactions related
    thereto, which are described on page 7; and
    our management, our employees, or
    similar terms refer to the management or other personnel of our
    general partner or, as applicable, provided to us or our general
    partner by Memorial Resource under an omnibus agreement among
    us, our general partner and Memorial Resource. v




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SUMMARY  This summary highlights information contained elsewhere in
    this prospectus. You should read the entire prospectus
    carefully, including Risk Factors beginning on
    page 22 and the historical and pro forma financial
    statements and the notes to those financial statements. The
    information presented in this prospectus assumes that the
    underwriters do not exercise their option to purchase additional
    common units, unless otherwise indicated.
  Unless we indicate otherwise, our financial, reserve and
    operating information in this prospectus is presented on a pro
    forma basis as if this offering and the other transactions
    contemplated by this prospectus, including the formation
    transactions, had occurred on January 1, 2010 or
    April 1, 2010, as applicable, in the case of pro forma
    financial income statement or operating data, and on
    December 31, 2010 or March 31, 2011, as applicable, in
    the case of pro forma balance sheet information. We include a
    glossary of some of the oil and natural gas industry terms used
    in this prospectus in Appendix B.
  The pro forma estimated proved reserve information for all of
    the Partnership Properties as of December 31, 2010
    contained in this prospectus is based on the following:
    (1) approximately 53% of the estimated proved reserve
    volumes are based on a reserve report relating to our South
    Texas properties prepared by the independent petroleum engineers
    of Netherland, Sewell & Associates, Inc. (or NSAI), a
    summary of which is included in this prospectus as
    Appendix C; (2) approximately 35% of the estimated
    proved reserve volumes are based on evaluations relating to
    certain of our East Texas properties prepared by Memorial
    Resources internal reserve engineers and audited by NSAI,
    a summary of which is included in this prospectus as
    Appendix D; and (3) the remaining approximately 12% of
    the estimated proved reserve volumes are based on a reserve
    report relating to certain of our East Texas properties prepared
    by the independent petroleum engineers of Miller and Lents, Ltd.
    (or Miller and Lents), a summary of which is included in this
    prospectus as Appendix E. We refer to these reports and
    evaluations collectively as our reserve reports.
  Memorial
    Production Partners LP
 Overview  reserve-to-production
 1




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Our
    Properties      Estimated Pro Forma


Average Net Pro


AverageNet Proved Reserves


Forma Production


Reserve-to-


Producing% Natural


% Proved








Production


WellsBcfe


Gas


Developed


MMcfe/d


%


Ratio(1)


Gross


Net(Years)South Texas


172.2



98
%


87
%


32



61
%


15



563



424East Texas


152.5



76
%


76
%


20



39
%


21



727



185Total


324.7



88
%


81
%


52



100
%


17



1,290



609     (1)
    
    The average
    reserve-to-production
    ratio is calculated by dividing estimated pro forma net proved
    reserves as of December 31, 2010 by average pro forma net
    production for the year ended December 31, 2010. Our
    Hedging Strategy  three-to-five
 2




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##### Table of Contents



Our
    Principal Business Relationships   Our
    Relationship with Memorial Resource      Estimated Pro Forma








AverageNet Proved Reserves(1)


Average Net Pro


Reserve-to-


Producing% Proved


Forma Production


Production


WellsBcfe


% Natural Gas


Developed


MMcfe/d


%


Ratio(2)


Gross


Net(Years)East Texas(3)


760.6



84%



30%



43



64%



48



1,067



306North Louisiana


224.7



73%



44%



18



27%



35



267



172Rockies


51.0



67%



41%



6



9%



25



123



85Total


1,036.3



81%



34%



67



100%



43



1,457



563     (1)
    
    Memorial Resources estimated pro forma net proved reserves
    are based primarily on reserve reports prepared by third-party
    independent petroleum engineers.(2)
    
    The average
    reserve-to-production
    ratio is calculated by dividing estimated pro forma net proved
    reserves as of December 31, 2010 by average pro forma net
    production for the year ended December 31, 2010.(3)
    
    Includes 169 Bcfe of reserves associated with properties in
    which we have a joint ownership interest. Please read
     Our Partnership Structure and Formation
    Transactions  Background Information Regarding Our
    Predecessor and the Partnership Properties.
 3




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Our
    Relationship with Natural Gas Partners and the
    Funds     Our
    Business Strategies    
    Maintain and grow a stable production profile through accretive
    acquisitions and low-risk development;
    Strategically utilize our relationship with Memorial Resource,
    the Funds, and their respective affiliates (including NGP) to
    gain access to and, from time to time, acquire producing oil and
    natural gas properties that meet our acquisition criteria;
 4




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##### Table of Contents




    Leverage our relationships with Memorial Resource, the Funds,
    and their respective affiliates (including NGP) to participate
    in acquisitions of third party producing properties and to
    increase the size and scope of our potential third-party
    acquisition targets;
    Exploit opportunities on our current properties and manage our
    operating costs and capital expenditures;
    Reduce exposure to commodity price risk and stabilize cash flows
    through a disciplined commodity hedging policy; and
    Maintain reasonable levels of indebtedness to permit us to
    opportunistically finance acquisitions.   Our
    Competitive Strengths    
    Our long-lived reserves with significant production history and
    predictable production decline rates;
    Our relationships with Memorial Resource, the Funds, and their
    respective affiliates (including NGP), which we believe will
    provide us with access to a portfolio of additional oil and
    natural gas properties that meet our acquisition criteria;
    Our management teams extensive experience in the
    acquisition, development and integration of oil and natural gas
    assets;
    Our relationship with Memorial Resource, which provides us with
    extensive technical expertise in and familiarity with developing
    and operating oil and natural gas assets within our core focus
    areas;
    Our relationships with Memorial Resource, the Funds, and their
    respective affiliates (including NGP), which we believe will
    help us with access to and in the evaluation and execution of
    future acquisitions;
    Our diverse distribution of reserve value, with 1,290 gross
    (609 net) producing wells as of December 31, 2010, none of
    which contains estimated proved reserves in excess of 2% of our
    total estimated proved reserves as of December 31, 2010;
    Our inventory of 345 proved low-risk infill drilling,
    recompletion and development opportunities in our core
    operational areas; and
    Our competitive cost of capital and financial flexibility.
 5




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Risk
    Factors    Risks
    Related to Our Business
  
    We may not have sufficient cash to pay the minimum quarterly
    distribution on our common units, following the establishment of
    cash reserves and payment of fees and expenses, including
    payments to our general partner and its affiliates.
    Our estimated oil and natural gas reserves will naturally
    decline over time, and it is unlikely that we will be able to
    sustain distributions at the level of our minimum quarterly
    distribution without making accretive acquisitions or
    substantial capital expenditures that maintain our asset base.
    Oil and natural gas prices are very volatile, and a decline in
    oil or natural gas prices will cause a decline in our cash flow
    from operations, which could cause us to reduce our
    distributions or cease paying distributions altogether.  Risks
    Inherent in an Investment in Us
  
    Our general partner and its affiliates own a controlling
    interest in us and will have conflicts of interest with, and owe
    limited fiduciary duties to, us, which may permit them to favor
    their own interests to the detriment of our unitholders.
    Memorial Resource, the Funds and other affiliates of our general
    partner will not be limited in their ability to compete with us,
    which could cause conflicts of interest and limit our ability to
    acquire additional assets or businesses.
    Neither we nor our general partner have any employees and we
    will rely solely on the employees of Memorial Resource to manage
    our business. The management team of Memorial Resource, which
    includes the individuals who will manage us, will also perform
    substantially similar services for itself and will own and
    operate its own assets, and thus will not be solely focused on
    our business.
    Our unitholders have limited voting rights and are not entitled
    to elect our general partner or its board of directors. Memorial
    Resource, as the owner of our general partner, will have the
    power to appoint and remove our general partners directors.
    Even if our unitholders are dissatisfied, they cannot remove our
    general partner without Memorial Resources consent.  Tax
    Risks to Unitholders
  
    Our tax treatment depends on our status as a partnership for
    federal income tax purposes. If the Internal Revenue Service, or
    the IRS, were to treat us as a corporation for federal income
    tax purposes, then our cash available for distribution to our
    unitholders would be substantially reduced.
    Our unitholders will be required to pay taxes on their share of
    our income even if they do not receive any cash distributions
    from us.
 6




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Our
    Partnership Structure and Formation Transactions      
    The Funds will contribute their respective controlling ownership
    interests in certain of their subsidiaries (including our
    predecessor) to Memorial Resource; and
    Memorial Resource will issue membership interests to the Funds
    reflecting an aggregate 100% membership interest in itself, and
    will agree to cause our general partner to issue to the Funds an
    aggregate 50% non-voting membership interest in itself to the
    Funds that will entitle the Funds to 50% of any cash
    distributions or common units received by our general partner in
    respect of our incentive distribution rights; and    
    Memorial Resource will cause certain of its subsidiaries,
    including our predecessor, to contribute to us
    (i) specified oil and natural gas properties, which we
    refer to collectively as the Partnership Properties,
    and (ii) commodity derivative contracts for the six months
    ending December 31, 2011 and the years ending
    December 31, 2012, 2013, 2014, and 2015 covering
    approximately 76%, 75%, 69%, 14% and 8%, respectively, of our
    estimated production from our total proved developed producing
    reserves existing as of December 31, 2010, based on our
    reserve reports;
    We will issue to Memorial
    Resource          
    common units
    and          subordinated
    units, representing an aggregate     %
    limited partner interest in us;
    We will issue to our general
    partner          
    general partner units, representing a 0.1% general partner
    interest in us, and all of our incentive distribution rights,
    which will entitle our general partner to increasing percentages
    of the cash we distribute in excess of
    $     per unit per quarter;
    Our general partner will issue an aggregate 50% non-voting
    membership interest in itself to the Funds that will entitle the
    Funds to 50% of any cash distributions or common units received
    by our general partner in respect of our incentive distribution
    rights;
    We expect to receive net proceeds of approximately
    $      million from the issuance
    and sale
    of          
    common units to the public (based on the midpoint of the price
    range set forth on the cover page of this prospectus),
    representing a     % limited partner
    interest in us, and we will use the net proceeds as described in
    Use of Proceeds;
    We expect to borrow approximately $130.0 million under a
    new $      million revolving
    credit facility, and we will use the proceeds as described in
    Use of Proceeds (if the net proceeds from this
    offering increase or decrease, then our borrowing under our new
    revolving credit facility would correspondingly decrease or
    increase, respectively); and
    We and our general partner will enter into an omnibus agreement
    with Memorial Resource, pursuant to which, among other things,
    Memorial Resource will provide us and our general partner with
    management, administrative and operating services.
 7




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Background
    Information Regarding Our Predecessor and the Partnership
    Properties
 8




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Our
    Ownership and Organizational Structure    OwnershipUnits


InterestCommon units held by the public







%Common units held by Memorial Resource







%Subordinated units held by Memorial Resource







%General partner units






0.1
%Total






100.0
%
 9




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Principal
    Executive Offices and Internet Address  (713) 579-5700.
 Management
    of the Partnership  and/or and/or
       Summary
    of Conflicts of Interest and Fiduciary Duties
 10




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
    purchases and sales of oil and natural gas properties and other
    acquisitions and dispositions, including whether to pursue
    acquisitions that are also suitable for Memorial Resource, the
    Funds or their affiliates;
    the manner in which our business is operated;
    the level of our borrowings;
    the amount, nature and timing of our capital
    expenditures; and
    the amount of cash reserves necessary or appropriate to satisfy
    our general and administrative expenses, other expenses and debt
    service requirements, and to otherwise provide for the proper
    conduct of our business.
 11




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The
    Offering  Common units offered hereby
    
    common
    units or      common units if the
    underwriters exercise in full their option to purchase
    additional common units.Units outstanding after this offering
    
    common
    units
    and          subordinated
    units, representing     %
    and     %, respectively, limited
    partner interests in us
    (          
    common units and subordinated units,
    representing     %
    and     %, respectively, limited
    partner interests in us if the underwriters exercise in full
    their option to purchase additional common units). The general
    partner will own general partner units,
    or          
    general partner units if the underwriters exercise their option
    to purchase additional common units in full, in each case
    representing a 0.1% general partner interest in us.Use of proceeds
    
    We intend to use the estimated net proceeds of approximately
    $      million from this offering,
    based upon the assumed initial public offering price of
    $      per common unit (the midpoint of
    the price range set forth on the cover of this prospectus),
    after deducting underwriting discounts, structuring fees and
    expenses, together with borrowings of approximately
    $130.0 million under our new revolving credit facility, to
    purchase the Partnership Properties from Memorial Resource and
    to pay fees and expenses associated with this offering and our
    formation transactions. We will use any net proceeds from the
    exercise of the underwriters option to purchase additional
    common units to repay additional indebtedness under our new
    revolving credit facility. Please read Use of
    Proceeds.Cash distributions
    
    We expect to make a minimum quarterly distribution of
    $      per unit per quarter on all
    common, subordinated and general partner units
    ($      per unit on an annualized
    basis) to the extent we have sufficient cash from operations
    after establishment of cash reserves and payment of fees and
    expenses, including payments to our general partner and its
    affiliates. We refer to this cash as available cash,
    and it is defined in our partnership agreement included in this
    prospectus as Appendix A. Our ability to pay the minimum
    quarterly distribution is subject to various restrictions and
    other factors described in more detail under the caption
    Our Cash Distribution Policy and Restrictions on
    Distributions. For the first quarter that we are publicly
    traded, we will pay our unitholders a prorated distribution
    covering the period from the completion of this offering
    through          ,
    2011, based on the actual length of that period.Assuming our general partner maintains its 0.1% general partner
    interest in us, our partnership agreement requires us to
    distribute all of our available cash each quarter in the
    following manner during the subordinated period: first, 99.9% to the holders of common units
    and 0.1% to our general partner, until each common unit has
    received the minimum quarterly distribution of
    $      plus any arrearages from prior
    quarters;
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##### Table of Contents



 second, 99.9% to the holders of subordinated
    units and 0.1% to our general partner, until each subordinated
    unit has received the minimum quarterly distribution of
    $     ; and third, 99.9% to all unitholders, pro rata,
    and 0.1% to our general partner, until each unit has received a
    distribution of $     .If cash distributions to our unitholders exceed
    $      per common and subordinated unit
    in any quarter, our general partner will receive, in addition to
    distributions on its general partner interest, increasing
    percentages, up to 24.9%, of the cash we distribute in excess of
    that amount. We refer to these distributions as incentive
    distributions. Please read Provisions of Our
    Partnership Agreement Relating to Cash Distributions.At the closing of this offering, the Funds will hold non-voting
    membership interests in our general partner that will entitle
    them to collectively receive 50% of any cash distributions made
    or common units issued to our general partner in respect of our
    incentive distribution rights. All other interests in our
    general partner will be owned by Memorial Resource. Please read
    Certain Relationships and Related Party
    Transactions  Amended and Restated Limited Liability
    Company Agreement of Memorial Production Partners GP LLC.Our ability to pay the minimum quarterly distribution is subject
    to various restrictions and other factors described in more
    detail in Our Cash Distribution Policy and Restrictions on
    Distributions.Pro forma cash available for distribution generated during the
    year ended December 31, 2010 was approximately
    $46.4 million, which would have been sufficient to allow us
    to pay the full minimum quarterly distribution on our common
    units, general partner units and subordinated units during that
    period (assuming the underwriters exercise in full their option
    to purchase additional common units).Pro forma cash available for distribution during the twelve
    months ended March 31, 2011 was approximately
    $40.6 million, which would have been sufficient to allow us
    to pay the full minimum quarterly distribution on our common
    units and general partner units, and a quarterly distribution of
    $     on our subordinated units, during
    that period (assuming the underwriters exercise in full their
    option to purchase additional common units).The amount of available cash we need to pay the minimum
    quarterly distribution for four quarters on our common units,
    general partner units and subordinated units to be outstanding
    immediately after this offering is approximately
    $      million (or an average of
    approximately $      million per
    quarter). Please read Our Cash Distribution Policy and
    Restrictions on Distributions.We believe, based on our financial forecast and related
    assumptions included in Our Cash Distribution Policy and
    Restrictions on Distributions  Estimated Adjusted
    EBITDA for the Twelve Months Ending June 30, 2012,
    that we will have sufficient available cash to
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pay the aggregate minimum quarterly distribution of
    $      million on all of our
    common units, general partner units and subordinated units for
    the twelve months ending June 30, 2012. However, we do not
    have a legal obligation to pay distributions at our minimum
    quarterly distribution rate or at any other rate except as
    provided in our partnership agreement, and there is no guarantee
    that we will make quarterly cash distributions to our
    unitholders. Please read Our Cash Distribution Policy and
    Restrictions on Distributions.Subordinated units
    
    Memorial Resource will initially own all of our subordinated
    units. The principal difference between our common units and
    subordinated units is that, in any quarter during the
    subordination period, the subordinated units are entitled to
    receive the minimum quarterly distribution only after the common
    units have received their minimum quarterly distribution plus
    any arrearages in the payment of the minimum quarterly
    distribution from prior quarters. Accordingly, holders of
    subordinated units may receive a smaller distribution than
    holders of common units or no distribution at all. Subordinated
    units will not accrue arrearages.The subordination period will begin on the closing date of this
    offering and will extend until the first business day of any
    quarter
    after          ,
    2014 that we have earned and paid from operating surplus, in the
    aggregate, distributions on each outstanding common unit,
    subordinated unit, and general partner unit equaling or
    exceeding the minimum quarterly distribution payable for a
    period of twelve consecutive quarters immediately preceding such
    date.The subordination period will also end if our general partner is
    removed other than for cause, provided that no subordinated or
    common units held by the holders of the subordinated units or
    their affiliates are voted in favor of such removal.When the subordination period ends, all subordinated units will
    convert into common units on a
    one-for-one
    basis and all common units thereafter will no longer be entitled
    to arrearages.Early conversion of subordinated units
    
    If we have earned and paid from operating surplus at least
    $      (125% of the minimum quarterly
    distribution) on each outstanding common unit, subordinated unit
    and general partner unit, and the related distribution on the
    incentive distribution rights, for each quarter in any
    four-quarter period ending on or
    after          ,
    2012, all of the outstanding subordinated units will convert
    into common units at the end of such period.Issuance of additional units
    
    We can issue an unlimited number of additional units, including
    units that are senior to the common units in right of
    distributions, liquidation and voting, on terms and conditions
    determined by our general partner, without the approval of our
    unitholders. Please read Units Eligible for Future
    Sale and The Partnership Agreement 
    Issuance of Additional Securities.Limited voting rights
    
    Our general partner will manage us and operate our business.
    Unlike stockholders of a corporation, our unitholders will have
    only limited voting rights on matters affecting our business.
    Our
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##### Table of Contents



unitholders will have no right to elect our general partner or
    its directors on an annual or other continuing basis. Our
    general partner may not be removed except by a vote of the
    holders of at least
    662/3%
    of the outstanding common and subordinated units, including any
    units owned by our general partner and its affiliates, voting
    together as a single class. Upon consummation of this offering,
    Memorial Resource and its affiliates will own an aggregate of
    approximately     % of our outstanding
    common and subordinated units (or     %
    of our outstanding common and subordinated units if the
    underwriters exercise their option to purchase additional common
    units in full) and will therefore be able to prevent the removal
    of our general partner. Please read The Partnership
    Agreement  Limited Voting Rights.Limited call right
    
    If at any time our general partner and its affiliates own more
    than 80% of the outstanding common units, our general partner
    has the right, but not the obligation, to purchase all of the
    remaining common units at a purchase price not less than the
    then-current market price of the common units, as calculated
    pursuant to the terms of our partnership agreement. Upon the
    consummation of this offering, Memorial Resource will own
    approximately     % of our outstanding
    common units (or     % of our
    outstanding common units if the underwriters exercise their
    option to purchase additional common units in full) and 100% of
    our subordinated units. Please read The Partnership
    Agreement  Limited Call Right.Estimated ratio of taxable income to distributions
    
    We estimate that if our unitholders own the common units
    purchased in this offering through the record date for
    distributions for the period
    ending          ,
    such unitholders will be allocated, on a cumulative basis, an
    amount of federal taxable income for that period that will be
    less than     % of the cash distributed
    to such unitholders with respect to that period. Please read
    Material Tax Consequences  Tax Consequences of
    Unit Ownership  Ratio of Taxable Income to
    Distributions for information regarding the bases for this
    estimate.Material tax consequences
    
    For a discussion of other material federal income tax
    consequences that may be relevant to prospective unitholders who
    are individual citizens or residents of the United States,
    please read Material Tax Consequences.Agreement to be bound by the partnership agreement
    
    By purchasing a common unit, you will be admitted as a
    unitholder of our partnership and will be deemed to have agreed
    to be bound by all of the terms of our partnership agreement.Listing and trading symbol
    
    We intend to apply to list our common units on the NASDAQ Global
    Market under the symbol MEMP.
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##### Table of Contents



Summary
    Historical and Pro Forma Financial Data        
    adjustments to reflect the acquisitions of oil and natural gas
    properties consummated in June 2010, April 2011, and May 2011 by
    our predecessor;
    the contribution by Memorial Resource and certain of its
    subsidiaries, including our predecessor, to us of the
    Partnership Properties in exchange
    for          
    common units,     subordinated units
    and $      million in cash and the
    issuance to our general partner
    of          
    general partner units, representing a 0.1% general partner
    interest in us, and all of our incentive distribution rights;
    the issuance and sale by us to the public
    of          
    common units in this offering and the application of the net
    proceeds as described in Use of Proceeds; and
    our borrowing of approximately $130.0 million under our new
    $      million revolving credit
    facility and the application of the net proceeds as described in
    Use of Proceeds. If the net proceeds from this
    offering increase or decrease, then our borrowing under our new
    revolving credit facility would correspondingly decrease or
    increase, respectively.
 16




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##### Table of Contents



Memorial ProductionPartners LPOur Predecessor


Pro FormaThreeMonthsThree Months Ended


Year Ended


EndedYear Ended December 31,


March 31,


December 31,


March 31,2008


2009


2010


2010


2011


2010


2011(Unaudited)


(Unaudited)(In thousands)Statement of Operations Data:Revenues:Oil and natural gas sales

$
49,313


$
24,541


$
37,308


$
7,879


$
11,641


$
87,762


$
20,648Other income


622



319



1,433



67



103



1,404



99Total revenues


49,935



24,860



38,741



7,946



11,744



89,166



20,747Costs and expenses:Lease operating


8,843



11,207



13,974



2,220



5,170



23,052



6,685Exploration


374



2,690



39











36



Production and ad valorem taxes


3,127



1,464



2,112



509



693



7,387



1,703Depreciation, depletion and amortization


12,353



15,226



20,066



4,352



4,450



34,772



7,026Impairment of proved oil and natural gas properties


14,166



3,480



11,800



1,691







9,509



General and administrative


3,835



4,811



6,116



1,108



1,474



5,819



1,399Accretion


224



320



663



64



210



1,072



276(Gain) loss on derivative instruments


(9,815
)


(10,834
)


(10,264
)


(6,636
)


703



(10,264
)


703Gain on sale of properties


(7,395
)


(7,851
)


(1
)






(8
)






Other, net






304



890











890



Total costs and expenses


25,712



20,817



45,395



3,308



12,692



72,273



17,792Operating income (loss)


24,223



4,043



(6,654
)


4,638



(948
)


16,893



2,955Interest expense


(3,138
)


(2,937
)


(4,438
)


(606
)


(1,035
)


(4,365
)


(1,092
)Income (loss) before income taxes

$
21,085


$
1,106


$
(11,092
)

$
4,032


$
(1,983
)

$
12,528


$
1,863Income tax expense










(225
)










(225
)


Net income (loss)

$
21,085


$
1,106


$
(11,317
)

$
4,032


$
(1,983
)

$
12,303


$
1,863Cash Flow Data:Net cash provided by operating activities

$
32,838


$
12,672


$
20,288


$
3,935


$
2,999Net cash (used in) investing activities


(45,547
)


(24,947
)


(116,687
)


(10,601
)


(7,898
)Net cash provided by financing activities


11,619



15,989



96,756



9,434



1,375Other Financial Data:Adjusted EBITDA

$
33,971


$
24,340


$
23,239


$
5,042


$
5,602


$
59,608


$
12,155
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##### Table of Contents



MemorialProductionPartners LPOur Predecessor

Pro FormaYear Ended December 31,

As of March 31,

As of March 31,2008

2009

2010

2011

2011(Unaudited)

(Unaudited)(In thousands)Balance Sheet Data:Working capital

$
(966
)

$
9,494


$
4,116


$
2,490


$
1,318Total assets


145,529



146,153



248,540



245,042



435,107Total debt


62,536



61,784



115,428



112,584



130,000Partners capital


54,576



72,988



105,801



108,039



278,543  Non-GAAP Financial
    Measure    
    Plus:  
    Interest expense, including realized and unrealized losses on
    interest rate derivative contracts;
    Income tax expense;
    Depreciation, depletion and amortization;
    Impairment of goodwill and long-lived assets (including oil and
    natural gas properties);
    Accretion of asset retirement obligations;
    Unrealized losses on commodity derivative contracts;
    Losses on sale of assets and other, net;
    Unit-based compensation expenses;
    Exploration costs; and
    Other non-routine items that we deem appropriate.  
    Less:  
    Interest income;
    Income tax benefit;
    Unrealized gains on commodity derivative contracts;
    Gains on sale of assets and other, net; and
    Other non-routine items that we deem appropriate.      
    our operating performance as compared to that of other companies
    and partnerships in our industry, without regard to financing
    methods, capital structure or historical cost basis; and
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##### Table of Contents




    the ability of our assets to generate cash sufficient to pay
    interest costs, support our indebtedness, and make distributions
    on our units.      Calculation
    of Adjusted EBITDA
  Memorial ProductionPartners LPOur Predecessor


Pro FormaYear


ThreeEnded


MonthsThree Months Ended


December


EndedYear Ended December 31,


March 31,


31,


March 31,2008


2009


2010


2010


2011


2010


2011(Unaudited)


(Unaudited)(In thousands)Net income (loss)

$
21,085


$
1,106


$
(11,317
)

$
4,032


$
(1,983
)

$
12,303


$
1,863Interest expense


3,138



2,937



4,438



606



1,035



4,365



1,092Income tax expense










225











225



Depreciation, depletion and amortization


12,353



15,226



20,066



4,352



4,450



34,772



7,026Impairment


14,166



3,480



11,800



1,691







9,509



Accretion of asset retirement obligations


224



320



663



64



210



1,072



276Unrealized (gains) losses on derivative instruments


(9,974
)


6,432



(2,674
)


(5,703
)


1,898



(2,674
)


1,898Gain on sale of properties


(7,395
)


(7,851
)


(1
)






(8
)






Unit-based compensation expense


























Exploration costs


374



2,690



39











36



Adjusted EBITDA

$
33,971


$
24,340


$
23,239


$
5,042


$
5,602


$
59,608


$
12,155   Reconciliation
    of Net Cash from Operating Activities to Adjusted
    EBITDA
  Our PredecessorThree Months EndedYear Ended December 31,


March 31,2008


2009


2010


2010


2011(Unaudited)(In thousands)Net cash provided by operating activities

$
32,838


$
12,672


$
20,288


$
3,935


$
2,999Changes in working capital


(1,979
)


8,840



(742
)


561



1,653Interest expense


3,138



2,937



4,438



606



1,035Amortization of deferred financing fees


(26
)


(109
)


(745
)


(60
)


(85
)Adjusted EBITDA

$
33,971


$
24,340


$
23,239


$
5,042


$
5,602
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##### Table of Contents



Summary
    Reserve and Pro Forma Operating Data        Reserve
    Data
  PartnershipProperties as ofDecember 31,2010Estimated Proved ReservesOil (MBbls)


2,002NGLs (MBbls)


4,502Natural gas (MMcf)


285,676Total (MMcfe)(1)


324,697Proved developed (MMcfe)


264,572Proved undeveloped (MMcfe)


60,125Proved developed reserves as a percentage of total proved
    reserves


81
%Standardized measure (in millions)(2)(3)

$
359.2Oil and Natural Gas Prices(4)Oil  WTI Posting (Plains) per Bbl

$
75.96Natural gas  NYMEXHenry Hub per MMBtu

$
4.38     (1)
    
    Determined using a ratio of six Mcf of natural gas to one Bbl of
    oil, condensate or NGLs based on an approximate energy
    equivalency. This is an energy content correlation and does not
    reflect a value or price relationship between the commodities.(2)
    
    Standardized measure is the present value of estimated future
    net revenues to be generated from the production of proved
    reserves, determined in accordance with the rules and
    regulations of the SEC without giving effect to non-property
    related expenses, such as general and administrative expenses,
    interest and income tax expenses, or to depreciation, depletion
    and amortization. The future cash flows are discounted using an
    annual discount rate of 10%. Because we are a limited
    partnership, we are generally not subject to federal income
    taxes and thus make no provision for federal income taxes in the
    calculation of our standardized measure. Standardized measure
    does not give effect to derivative transactions. We expect to
    hedge a substantial portion of our future estimated production
    from total proved producing reserves. For a description of our
    expected commodity derivative contracts, please read
    Managements Discussion and
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##### Table of Contents



Analysis of Financial Condition and Results of
    Operations  Pro Forma Liquidity and Capital
    Resources  Commodity Derivative Contracts.(3)
    
    Because we are subject to Texas margin tax, our standardized
    measure was negatively impacted by $5.0 million.(4)
    
    Our estimated net proved reserves and related standardized
    measure were determined using index prices for oil and natural
    gas, without giving effect to derivative contracts, held
    constant throughout the life of the properties. These prices
    were adjusted by lease for quality, transportation fees,
    geographical differentials, marketing bonuses or deductions and
    other factors affecting the price received at the wellhead.  Pro
    Forma Operating Data
  Memorial ProductionPartners LPPro FormaThree MonthsYear Ended

EndedDecember 31,

March 31,2010

2011(Unaudited)Production and operating data:Net production volumes:Oil (MBbls)


107



28NGLs (MBbls)


272



56Natural gas (MMcf)


16,713



3,897Total (MMcfe)


18,985



4,399Average net production (MMcfe/d)


52



49Average sales price:(1)Oil (per Bbl)

$
74.35


$
90.11NGLs (per Bbl)

$
37.41


$
43.76Natural gas (per Mcf)

$
4.17


$
4.02Average price per Mcfe

$
4.62


$
4.69Average unit costs per Mcfe:Lease operating expenses

$
1.21


$
1.52Production and ad valorem taxes

$
0.39


$
0.39General and administrative expenses

$
0.31


$
0.32Depreciation, depletion and amortization

$
1.83


$
1.60     (1)
    
    Prices do not include the effects of derivative cash settlements.
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##### Table of Contents



RISK
    FACTORS  Limited partner interests are inherently different from the
    capital stock of a corporation, although many of the business
    risks to which we are subject are similar to those that would be
    faced by a corporation engaged in a business similar to ours.
    Prospective unitholders should carefully consider the following
    risk factors together with all of the other information included
    in this prospectus in evaluating an investment in our common
    units.
  If any of the following risks were actually to occur, our
    business, financial condition or results of operations could be
    materially adversely affected. In that case, we might not be
    able to pay distributions on our common units, the trading price
    of our common units could decline and our unitholders could lose
    all or part of their investment.
 Risks
    Related to Our Business  We may
    not have sufficient cash to pay the minimum quarterly
    distribution on our common units, following the establishment of
    cash reserves and payment of fees and expenses, including
    payments to our general partner and its
    affiliates.
        
    the amount of oil, natural gas and NGLs we produce;
    the prices at which we sell our oil, natural gas and NGL
    production;
    the effectiveness of our commodity price hedging strategy;
    the costs of developing, producing and transporting our oil and
    natural gas assets, including costs attributable to governmental
    regulation and taxation;
    the level of our capital expenditures, including scheduled and
    unexpected maintenance expenditures;
    the cost of acquisitions;
    our ability to borrow funds, whether under our new revolving
    credit facility or otherwise, and to access capital markets;
    prevailing economic conditions;
    sources of cash used to fund acquisitions;
    debt service requirements and restrictions on distributions
    contained in our new revolving credit facility or future debt
    agreements and other liabilities;
    interest payments;
    fluctuations in our working capital needs;
    timing and collectability of receivables; 22




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
    governmental regulations and taxation;
    the amount of our operating expense and general and
    administrative expenses, including reimbursements to Memorial
    Resource in respect of those expenses;
    the amount of cash reserves (which we expect to be substantial)
    established by our general partner for the proper conduct of our
    business and for capital expenditures to maintain our production
    levels over the long-term; and
    other business risks affecting our cash levels.      If the
    underwriters exercise their option to purchase additional common
    units in full, we would not have generated sufficient available
    cash on a pro forma basis to have paid the minimum quarterly
    distribution on our subordinated units for the twelve months
    ended March 31, 2011.
    The
    assumptions underlying the forecast of cash available for
    distribution that we include in Our Cash Distribution
    Policy and Restrictions on Distributions are inherently
    uncertain and are subject to significant business, economic,
    financial, legal, regulatory and competitive risks and
    uncertainties that could cause actual results to differ
    materially from those estimated.
   23




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##### Table of Contents



Our
    estimated oil and natural gas reserves will naturally decline
    over time, and it is unlikely that we will be able to sustain
    distributions at the level of our minimum quarterly distribution
    without making accretive acquisitions or substantial capital
    expenditures that maintain our asset base.
      None
    of the proceeds of this offering will be used to maintain or
    grow our asset base or be reserved for future
    distributions.
    Our
    acquisition and development operations will require substantial
    capital expenditures, and we expect to fund these capital
    expenditures using cash generated from our operations,
    additional borrowings or the issuance of additional partnership
    interests, or some combination thereof, which could adversely
    affect our ability to pay distributions at the then-current
    distribution rate or at all.
      
    our estimated proved oil and natural gas reserves;
    the amount of oil, natural gas and NGL we produce; 24




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
    the prices at which we sell our production;
    the costs of developing, producing and transporting our oil and
    natural gas assets, including costs attributable to governmental
    regulation and taxation;
    our ability to acquire, locate and produce new reserves;
    fluctuations in our working capital needs;
    interest payments and debt service requirements;
    prevailing economic conditions;
    the ability and willingness of banks to lend to us; and
    our ability to access the equity and debt capital markets.      Oil
    and natural gas prices are very volatile, and a decline in oil
    or natural gas prices will cause a decline in our cash flow from
    operations, which could cause us to reduce our distributions or
    cease paying distributions altogether.
    
    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;
    weather conditions, seasonal trends and the occurrence of
    natural disasters;
    anticipated future prices of oil and natural gas and other
    commodities;
    overall domestic and global economic conditions;
    political and economic conditions in oil and natural gas
    producing countries globally, including terrorist attacks, civil
    unrest, political demonstrations, mass strikes or additional
    outbreaks of armed hostilities or other crises and threats,
    escalation of military activity in response to such activities
    or acts of war;
    actions of the Organization of the Petroleum Exporting
    Countries, or OPEC, and other state-controlled oil companies
    relating to oil price and production controls; 25




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
    the effect of increasing liquefied natural gas, or LNG,
    deliveries to and exports from the United States;
    the impact of the U.S. dollar exchange rates on oil and
    natural gas prices;
    technological advances affecting energy supply and energy
    consumption;
    domestic and foreign governmental regulations and taxation;
    the impact of energy conservation efforts;
    the proximity, capacity, cost and availability of oil and
    natural gas pipelines and other transportation facilities;
    the availability of refining capacity; and
    the price and availability of alternative fuels.        
    limit our ability to enter into hedging contracts at attractive
    prices;
    reduce the value and quantities of our reserves, because
    declines in oil and natural gas prices would reduce the amount
    of oil and natural gas that we can economically produce;
    reduce the amount of cash flow available for capital
    expenditures;
    limit our ability to borrow money or raise additional
    capital; and
    impair our ability to pay distributions to our unitholders.    An
    increase in the differential between the NYMEX or other
    benchmark prices of oil and natural gas and the wellhead price
    we receive for our production could significantly reduce our
    cash available for distribution and adversely affect our
    financial condition.
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Future
    commodity price declines, increased capital costs, changes in
    well performance, delays in asset development or deterioration
    of drilling results may result in a write-down of our asset
    carrying values, which could adversely affect our results of
    operations.
  field-by-field
  Our
    hedging strategy may be ineffective in removing the impact of
    commodity price volatility from our cash flows, which could
    result in financial losses or could reduce our income, which may
    adversely affect our ability to pay distributions to our
    unitholders.
  three-to-five
    Our
    hedging activities could result in cash losses, could reduce our
    cash available for distributions and may limit potential
    gains.
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Our
    hedging transactions expose us to counterparty credit
    risk.
    Our
    estimated proved reserves and future production rates are based
    on many assumptions that may prove to be inaccurate. Any
    material inaccuracies in these reserve estimates or underlying
    assumptions will materially affect the quantities and present
    value of our estimated reserves.
    
    the level of oil and natural gas prices;
    future production levels;
    capital expenditures;
    operating and development costs;
    the effects of regulation;
    the accuracy and reliability of the underlying engineering and
    geologic data; and
    the availability of funds.        The
    standardized measure of our estimated proved reserves is not
    necessarily the same as the current market value of our
    estimated proved oil and natural gas reserves.
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
    the actual prices we receive for natural gas, oil and NGLs;
    our actual operating costs in producing natural gas, oil and
    NGLs;
    the amount and timing of actual production;
    the amount and timing of our capital expenditures;
    the supply of and demand for natural gas, oil and NGLs; and
    changes in governmental regulations or taxation.    Developing
    and producing oil and natural gas are costly and high-risk
    activities with many uncertainties that could adversely affect
    our financial condition or results of operations and, as a
    result, our ability to pay distributions to our
    unitholders.
    
    high costs, shortages or delivery delays of rigs, equipment,
    labor or other services;
    composition of sour natural gas, including sulfur and mercaptan
    content;
    unexpected operational events and conditions;
    reductions in oil and natural gas prices;
    increases in severance taxes;
    adverse weather conditions and natural disasters;
    facility or equipment malfunctions and equipment failures or
    accidents, including acceleration of deterioration of our
    facilities and equipment due to the highly corrosive nature of
    sour natural gas;
    title problems;
    pipe or cement failures, casing collapses or other downhole
    failures;
    compliance with ever-changing environmental and other
    governmental requirements;
    environmental hazards, such as natural gas leaks, oil spills,
    salt water spills, pipeline ruptures and discharges of toxic
    gases;
    lost or damaged oilfield development and service tools;
    unusual or unexpected geological formations and pressure or
    irregularities in formations;
    loss of drilling fluid circulation;
    fires, blowouts, surface craterings and explosions;
    uncontrollable flows of oil, natural gas or well fluids; 29




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
    loss of leases due to incorrect payment of royalties; and
    other hazards, including those associated with sour natural gas
    such as an accidental discharge of hydrogen sulfide gas, that
    could also result in personal injury and loss of life, pollution
    and suspension of operations.      Many
    of our properties are in areas that may have been partially
    depleted or drained by offset wells.
    Our
    expectations for future development activities are planned to be
    realized over several years, making them susceptible to
    uncertainties that could materially alter the occurrence or
    timing of such activities.
    Shortages
    of rigs, equipment and crews could delay our operations and
    reduce our cash available for distribution to our
    unitholders.
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If we
    do not make acquisitions on economically acceptable terms, our
    future growth and ability to pay or increase distributions will
    be limited.
    
    unable to identify attractive acquisition candidates or
    negotiate acceptable purchase contracts with their owners;
    unable to obtain financing for such acquisitions on economically
    acceptable terms; or
    outbid by competitors.    Any
    acquisitions we complete will be subject to substantial risks
    that could reduce our ability to make distributions to
    unitholders.
    
    mistaken assumptions about estimated proved reserves, future
    production, revenues, capital expenditures, operating expenses
    and costs, including synergies;
    an inability to successfully integrate the assets or businesses
    we acquire;
    a decrease in our liquidity by using a significant portion of
    our available cash or borrowing capacity to finance acquisitions;
    a significant increase in our interest expense or financial
    leverage if we incur additional debt to finance acquisitions;
    the assumption of unknown liabilities, losses or costs for which
    we are not indemnified or for which any indemnity we receive is
    inadequate;
    the diversion of managements attention from other business
    concerns;
    mistaken assumptions about the overall cost of equity or debt;
    an inability to hire, train or retain qualified personnel to
    manage and operate our growing business and assets;
    facts and circumstances that could give rise to significant cash
    and certain non-cash charges; and
    customer or key employee losses at the acquired businesses.     31




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Adverse
    developments in our operating areas would reduce our ability to
    make distributions to our unitholders.
    We may
    experience a financial loss if Memorial Resource is unable to
    sell, or receive payment for, a significant portion of our oil
    and natural gas production.
        We may
    be unable to compete effectively with larger companies, which
    may adversely affect our ability to generate sufficient revenue
    to allow us to pay distributions to our
    unitholders.
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We may
    incur substantial additional debt to enable us to pay our
    quarterly distributions, which may negatively affect our ability
    to pay future distributions or execute our business
    plan.
    Our
    future debt levels may limit our ability to obtain additional
    financing and pursue other business opportunities.
    
    our ability to obtain additional financing, if necessary, for
    working capital, capital expenditures, acquisitions or other
    purposes may be impaired or such financing may not be available
    on favorable terms;
    covenants contained in our new revolving credit facility and
    future debt arrangements will require us to meet financial tests
    that may affect our flexibility in planning for and reacting to
    changes in our business, including possible acquisition
    opportunities;
    we may need a substantial portion of our cash flow to make
    principal and interest payments on our indebtedness, reducing
    the funds that would otherwise be available for operations,
    future business opportunities and distributions to our
    unitholders; and
    our debt level will make us more vulnerable than our competitors
    with less debt to competitive pressures or a downturn in our
    business or the economy generally.  and/or
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Our
    new revolving credit facility will have restrictions and
    financial covenants that may restrict our business and financing
    activities and our ability to pay distributions to our
    unitholders.
        Our
    operations are subject to operational hazards and unforeseen
    interruptions for which we may not be adequately
    insured.
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Our
    business depends in part on pipelines, gathering systems and
    processing facilities owned by others. Any limitation in the
    availability of those facilities could interfere with our
    ability to market our oil and natural gas production and could
    harm our business.
    The
    operation of our properties is largely dependent on the ability
    of Memorial Resources employees.
    
    the nature and timing of drilling and operational activities;
    the timing and amount of capital expenditures;
    Memorial Resources or the operators expertise and
    financial resources;
    the approval of other participants in such properties; and
    the selection and application of suitable technology.   35




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Our
    historical and pro forma financial information may not be
    representative of our future performance.
      We are
    subject to complex federal, state, local and other laws and
    regulations that could adversely affect the cost, manner or
    feasibility of conducting our operations.
      Climate
    change legislation or regulations restricting emissions of
    greenhouse gases could result in increased operating
    costs and reduced demand for the oil and natural gas that we
    produce.
   36




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2 2012-2016. cap-and-trade and/or
  Our
    operations are subject to environmental and operational safety
    laws and regulations that may expose us to significant costs and
    liabilities.
   37




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The
    third parties on whom we rely for gathering and transportation
    services are subject to complex federal, state and other laws
    that could adversely affect the cost, manner or feasibility of
    conducting our business.
    The
    recent adoption of derivatives legislation by the U.S. Congress
    could have an adverse effect on our ability to use derivative
    contracts to reduce the effect of commodity price, interest rate
    and other risks associated with our business.
  over-the-counter
 38




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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.
      Increases
    in interest rates could adversely impact our unit price and our
    ability to issue additional equity and incur debt.
   Risks
    Inherent in an Investment in Us  Our
    general partner and its affiliates own a controlling interest in
    us and will have conflicts of interest with, and owe limited
    fiduciary duties to, us, which may permit them to favor their
    own interests to the detriment of our unitholders.
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and/or
  
    neither our partnership agreement nor any other agreement
    requires Memorial Resource, the Funds or NGP to pursue a
    business strategy that favors us. The directors and officers of
    Memorial Resource, the Funds and their respective affiliates
    (including NGP) have a fiduciary duty to make decisions in the
    best interests of their respective equity holders, which may be
    contrary to our interests;
    our general partner is allowed to take into account the
    interests of parties other than us, such as its owner, in
    resolving conflicts of interest, which has the effect of
    limiting its fiduciary duty to our unitholders;
    Memorial Resource, the Funds and their affiliates (including
    NGP) are not limited in their ability to compete with us,
    including with respect to future acquisition opportunities, and
    are under no obligation to offer assets to us. Please read
    Conflicts of Interest and Fiduciary Duties 
    Conflicts of Interest  Memorial Resource, the Funds
    and other affiliates of our general partner will not be limited
    in their ability to compete with us, which could cause conflicts
    of interest and limit our ability to acquire additional assets
    or businesses;
    except in limited circumstances, our general partner has the
    power and authority to conduct our business without unitholder
    approval;
    many of the officers and directors of our general partner who
    will provide services to us will devote time to affiliates of
    our general partner, including Memorial Resource, the Funds,
    and/or NGP,
    and may be compensated for services rendered to such affiliates;
    our general partner has limited its liability and reduced its
    fiduciary duties, and has also restricted the remedies available
    to our unitholders for actions that, without such limitations,
    reductions, and restrictions, might constitute breaches of
    fiduciary duty. By purchasing common units, unitholders are
    consenting to some actions and conflicts of interest that might
    otherwise constitute a breach of fiduciary or other duties under
    applicable law;
    our general partner determines the amount and timing of our
    drilling program and related capital expenditures, asset
    purchases and sales, borrowings, issuance of additional
    partnership interests, other investments, including investment
    capital expenditures in other partnerships with which our
    general partner is or may become affiliated, and the creation,
    reduction or increase of cash reserves, each of which can affect
    the amount of cash that is distributed to unitholders;
    our general partner determines whether a cash expenditure is
    classified as a growth capital expenditure, which does not
    reduce operating surplus. This determination can affect the
    amount of cash that is distributed to our unitholders and to our
    general partner, the amount of adjusted operating surplus in any
    given period and the ability of the subordinated units to
    convert into common units;
    we and our general partner will enter into an omnibus agreement
    with Memorial Resource in connection with this offering,
    pursuant to which, among other things, Memorial Resource will
    operate 40




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our assets and perform other management, administrative, and
    operating services for us and our general partner;  
    our general partner is entitled to determine which costs,
    including allocated overhead, incurred by it and its affiliates,
    including Memorial Resource, are reimbursable by us, which will
    include salary, bonus, incentive compensation and other amounts
    paid to persons who perform services for us or on our behalf,
    and expenses allocated to our general partner by its affiliates;
    our general partner may cause us to borrow funds in order to
    permit the payment of cash distributions, even if the purpose or
    effect of the borrowing is to make a distribution on the
    subordinated units, to make incentive distributions or to
    accelerate the expiration of the subordination period;
    our partnership agreement permits us to classify up to
    $      million as operating
    surplus, even if it is generated from asset sales, non-working
    capital borrowings or other sources that would otherwise
    constitute capital surplus. This cash may be used to fund
    distributions on our subordinated units or to our general
    partner in respect of the general partner interest or the
    incentive distribution rights;
    our general partner decides whether to retain separate counsel,
    accountants, or others to perform services for us;
    our general partner may elect to cause us to issue common units
    to it in connection with a resetting of the target distribution
    levels related to our general partners incentive
    distribution rights without the approval of the conflicts
    committee of the board of directors of our general partner or
    our unitholders. This election may result in lower distributions
    to our common unitholders in certain situations;
    our partnership agreement does not restrict our general partner
    from causing us to pay it or its affiliates for any services
    rendered to us or entering into additional contractual
    arrangements with any of these entities on our behalf;
    our general partner intends to limit its liability regarding our
    contractual and other obligations and, in some circumstances, is
    entitled to be indemnified by us;
    our general partner may exercise its limited right to call and
    purchase common units if it and its affiliates own more than 80%
    of the common units;
    our general partner controls the enforcement of obligations owed
    to us by our general partner and its affiliates, including
    Memorial Resource, the Funds and NGP; and
    our general partner decides whether to retain separate counsel,
    accountants or others to perform services for us.    Memorial
    Resource, the Funds and other affiliates of our general partner
    will not be limited in their ability to compete with us, which
    could cause conflicts of interest and limit our ability to
    acquire additional assets or businesses.
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Neither
    we nor our general partner have any employees and we will rely
    solely on the employees of Memorial Resource to manage our
    business. The management team of Memorial Resource, which
    includes the individuals who will manage us, will also perform
    substantially similar services for itself and will own and
    operate its own assets, and thus will not be solely focused on
    our business.
      Our
    predecessor has material weaknesses in its internal control over
    financial reporting. If we fail to establish and maintain
    effective internal control over financial reporting, our ability
    to accurately report our financial results could be adversely
    affected.
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If we
    fail to develop or maintain an effective system of internal
    controls, we may not be able to accurately report our financial
    results or prevent fraud. As a result, current and potential
    unitholders could lose confidence in our financial reporting,
    which would harm our business and the trading price of our
    units.
    Many
    of the directors and all of the officers who have responsibility
    for our management have significant duties with, and will spend
    significant time serving, entities that compete with us in
    seeking acquisitions and business opportunities and,
    accordingly, may have conflicts of interest in allocating time
    or pursuing business opportunities.
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Cost
    reimbursements due to Memorial Resource and our general partner
    for services provided to us or on our behalf will be substantial
    and will reduce our cash available for distribution to our
    unitholders. The amount and timing of such reimbursements will
    be determined by our general partner.
        
    an omnibus agreement pursuant to which, among other things,
    Memorial Resource will provide management, administrative and
    operating services for us and our general partner; and
    a tax sharing agreement pursuant to which we will pay Memorial
    Resource (or its applicable affiliate(s)) our share of state and
    local income and other taxes for which our results are included
    in a combined or consolidated tax return filed by Memorial
    Resource or its applicable affiliate(s). It is possible that
    Memorial Resource or its applicable affiliate(s) may use its tax
    attributes to cause its combined or consolidated group, of which
    we may be a member for this purpose, to owe less or no tax. In
    such a situation, we would pay Memorial Resource or its
    applicable affiliate(s) the tax we would have owed had the tax
    attributes not been available or used for our benefit, even
    though Memorial Resource or its applicable affiliate(s) had no
    cash tax expense for that period. Currently, the Texas Margin
    tax (which has a maximum effective tax rate of 0.7% of federal
    gross income apportioned to Texas) is the only tax that will be
    included in a combined or consolidated tax return with Memorial
    Resource or its applicable affiliate(s). 44




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Our
    general partner may elect to cause us to issue common units to
    it in connection with a resetting of the target distribution
    levels related to our general partners incentive
    distribution rights without the approval of the conflicts
    committee of the board of directors of our general partner or
    our unitholders. This election may result in lower distributions
    to our common unitholders in certain situations.
      Our
    unitholders who fail to furnish certain information requested by
    our general partner or who our general partner determines are
    not eligible citizens may not be entitled to receive
    distributions in kind upon our liquidation and their common
    units will be subject to redemption.
    Common
    units held by persons who are non-taxpaying assignees will be
    subject to the possibility of redemption.
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Our
    unitholders have limited voting rights and are not entitled to
    elect our general partner or its board of directors. Memorial
    Resource, as owner of our general partner, will have the power
    to appoint and remove our general partners
    directors.
      Our
    general partner will be required to deduct estimated maintenance
    capital expenditures from our operating surplus, which may
    result in less cash available for distribution to unitholders
    from operating surplus than if actual maintenance capital
    expenditures were deducted.
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Our
    partnership agreement limits our general partners
    fiduciary duties to unitholders and restricts the remedies
    available to unitholders for actions taken by our general
    partner that might otherwise constitute breaches of fiduciary
    duty.
    
    permits our general partner to make a number of decisions in its
    individual capacity, as opposed to in its capacity as our
    general partner. This entitles our general partner to consider
    only the interests and factors that it desires, and it has no
    duty or obligation to give any consideration to any interest of,
    or factors affecting, us, our affiliates or any limited partner.
    Examples include the exercise of its limited call right, the
    exercise of its rights to transfer or vote the units it owns,
    the exercise of its registration rights and its determination
    whether or not to consent to any merger or consolidation
    involving us or to any amendment to the partnership agreement;
    provides that our general partner will not have any liability to
    us or our unitholders for decisions made in its capacity as
    general partner so long as it acted in good faith;
    generally provides that affiliated transactions and resolutions
    of conflicts of interest not approved by the conflicts committee
    of the board of directors of our general partner acting in good
    faith and not involving a vote of unitholders must be on terms
    no less favorable to us than those generally being provided to
    or available from unrelated third parties or must be fair
    and reasonable to us, as determined by our general partner
    in good faith. In determining whether a transaction or
    resolution is fair and reasonable, our general
    partner may consider the totality of the relationships between
    the parties involved, including other transactions that may be
    particularly advantageous or beneficial to us;
    provides that our general partner and its officers and directors
    will not be liable for monetary damages to us or our limited
    partners for any acts or omissions unless there has been a final
    and non-appealable judgment entered by a court of competent
    jurisdiction determining that our general partner or its
    officers and directors acted in bad faith or engaged in fraud or
    willful misconduct or, in the case of a criminal matter, acted
    with knowledge that the conduct was criminal; and
    provides that in resolving conflicts of interest, it will be
    presumed that in making its decision our general partners
    board of directors or the conflicts committee of our general
    partners board of directors acted in good faith, and in
    any proceeding brought by or on behalf of any limited partner or
    us, the person bringing or prosecuting such proceeding will have
    the burden of overcoming such presumption.    Even
    if our unitholders are dissatisfied, they cannot remove our
    general partner without Memorial Resources
    consent.
  2 3
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Control
    of our general partner and its incentive distribution rights may
    be transferred to a third party without unitholder
    consent.
      We may
    not make cash distributions during periods when we record net
    income.
    We may
    issue an unlimited number of additional units, including units
    that are senior to the common units, without unitholder
    approval, which would dilute unitholders ownership
    interests.
    
    our unitholders proportionate ownership interest in us
    will decrease;
    the amount of cash available for distribution on each unit may
    decrease;
    because a lower percentage of total outstanding units will be
    subordinated units, the risk that a shortfall in the payment of
    the minimum quarterly distribution will be borne by our common
    unitholders will increase;
    the ratio of taxable income to distributions may increase;
    the relative voting strength of each previously outstanding unit
    may be diminished; and
    the market price of our common units may decline.  Our
    partnership agreement restricts the limited voting rights of
    unitholders, other than our general partner and its affiliates,
    owning 20% or more of our common units, which may limit the
    ability of significant unitholders to influence the manner or
    direction of management.
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Once
    our common units are publicly traded, Memorial Resource may sell
    common units in the public markets, which sales could have an
    adverse impact on the trading price of the common
    units.
    Our
    general partner has a call right that may require common
    unitholders to sell their common units at an undesirable time or
    price.
    If we
    distribute cash from capital surplus, which is analogous to a
    return of capital, our minimum quarterly distribution will be
    reduced proportionately.
    Our
    unitholders liability may not be limited if a court finds
    that unitholder action constitutes control of our
    business.
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
    a court or government agency determined that we were conducting
    business in a state but had not complied with that particular
    states partnership statute; or
    a unitholders right to act with other unitholders to
    remove or replace the general partner, to approve some
    amendments to our partnership agreement or to take other actions
    under our partnership agreement constitute control
    of our business.    Our
    unitholders may have liability to repay
    distributions.
  Section 17-607
  Our
    unitholders may have limited liquidity for their common units, a
    trading market may not develop for the common units and our
    unitholders may be unable to resell their common units at the
    initial public offering price.
  180-day lock-up lock-up
  If our
    common unit price declines after the initial public offering,
    our unitholders could lose a significant part of their
    investment.
    
    changes in commodity prices; 50




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
    changes in securities analysts recommendations and their
    estimates of our financial performance;
    public reaction to our press releases, announcements and filings
    with the SEC;
    fluctuations in broader securities market prices and volumes,
    particularly among securities of oil and natural gas companies
    and securities of publicly traded limited partnerships and
    limited liability companies;
    changes in market valuations of similar companies;
    departures of key personnel;
    commencement of or involvement in litigation;
    variations in our quarterly results of operations or those of
    other oil and natural gas companies;
    variations in the amount of our quarterly cash distributions to
    our unitholders;
    future issuances and sales of our common units; and
    changes in general conditions in the U.S. economy,
    financial markets or the oil and natural gas industry.    Because
    we are a relatively small company, the requirements of being a
    public company, including compliance with the reporting
    requirements of the Securities Exchange Act of 1934 and the
    requirements of the Sarbanes-Oxley Act may strain our resources,
    increase our costs and distract management, and we may be unable
    to comply with these requirements in a timely or cost-effective
    manner.
    
    institute a more comprehensive compliance function;
    design, establish, evaluate and maintain a system of internal
    controls over financial reporting in compliance with the
    requirements of Section 404 of the Sarbanes-Oxley Act of
    2002 and the related rules and regulations of the SEC and the
    Public Company Accounting Oversight Board;
    comply with rules promulgated by NASDAQ;
    prepare and distribute periodic public reports in compliance
    with our obligations under the federal securities laws;
    establish new internal policies, such as those relating to
    disclosure controls and procedures and insider trading;
    involve and retain to a greater degree outside counsel and
    accountants in the above activities; and
    establish an investor relations function.   51




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Our
    unitholders will experience immediate and substantial dilution
    of $      per unit.
    Our
    partnership agreement requires that we distribute all of our
    available cash, which could limit our ability to grow our
    reserves and production.
    
    general economic and market conditions, including interest
    rates, prevailing at the time we desire to issue securities or
    borrow funds;
    conditions in the oil and natural gas industry;
    the market price of, and demand for, our common units;
    our results of operations and financial condition; and
    prices for oil and natural gas. 52




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NASDAQ
    does not require a publicly traded limited partnership like us
    to comply with certain of its corporate governance
    requirements.
   Tax Risks
    to Unitholders    Our
    tax treatment depends on our status as a partnership for federal
    income tax purposes. If the IRS were to treat us as a
    corporation for federal income tax purposes, then our cash
    available for distribution to our unitholders would be
    substantially reduced.
        If we
    were subjected to a material amount of additional entity-level
    taxation by individual states, it would reduce our cash
    available for distribution to our unitholders.
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The
    tax treatment of publicly traded partnerships or an investment
    in our units could be subject to potential legislative, judicial
    or administrative changes and differing interpretations,
    possibly on a retroactive basis.
      Certain
    U.S. federal income tax deductions currently available with
    respect to oil and natural gas exploration and production may be
    eliminated as a result of future legislation.
    If the
    IRS contests any of the federal income tax positions we take,
    the market for our units may be adversely affected, and the
    costs of any IRS contest will reduce our cash available for
    distribution to our unitholders.
    Our
    unitholders will be required to pay taxes on their share of our
    income even if they do not receive any cash distributions from
    us.
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Tax
    gain or loss on the disposition of our units could be more or
    less than expected.
    Tax-exempt
    entities and
    non-U.S.
    persons face unique tax issues from owning our units that may
    result in adverse tax consequences to them.
  non-U.S. persons non-U.S. persons non-U.S. persons non-U.S. persons
  We
    will treat each purchaser of units as having the same tax
    benefits without regard to the actual units purchased. The IRS
    may challenge this treatment, which could adversely affect the
    value of the units.
    We
    will prorate our items of income, gain, loss and deduction for
    U.S. federal income tax purposes between transferors and
    transferees of our units each month based upon the ownership of
    our units on the first day of each month, instead of on the
    basis of the date a particular unit is transferred. The IRS may
    challenge this treatment, which could change the allocation of
    items of income, gain, loss and deduction among our
    unitholders.
   55




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##### Table of Contents



A
    unitholder whose units are loaned to a short seller
    to cover a short sale of units may be considered to have
    disposed of those units. If so, he would no longer be treated
    for federal income tax purposes as a partner with respect to
    those units during the period of the loan and may recognize gain
    or loss from the disposition.
    We
    will adopt certain valuation methodologies and monthly
    conventions for U.S. federal income tax purposes that may result
    in a shift of income, gain, loss and deduction between our
    general partner and our unitholders. The IRS may challenge this
    treatment, which could adversely affect the value of our common
    units.
      The
    sale or exchange of 50% or more of our capital and profits
    interests during any twelve-month period will result in the
    termination of our partnership for federal income tax
    purposes.
   56




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##### Table of Contents



Schedule K-1
  As a
    result of investing in our units, our unitholders may become
    subject to state and local taxes and return filing requirements
    in jurisdictions where we operate or own or acquire
    property.
   57




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##### Table of Contents



USE OF
    PROCEEDS      Sources of Cash (In millions)


Uses of Cash (In millions)Gross proceeds from this offering(1)

$



Cash consideration to Memorial Resource

$Borrowings under new revolving credit facility(1)


130.0


Underwriting discounts, structuring fees and other offering and
    formation-related fees and expenses payable by usTotal

$



Total

$     (1)
    
    If the underwriters exercise their option to purchase additional
    common units in full, the gross proceeds would be
    $     and the amount borrowed under our
    new revolving credit facility would be approximately
    $      million.     58




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##### Table of Contents



CAPITALIZATION    
    the historical capitalization of our predecessor as of
    March 31, 2011; and
    our pro forma capitalization as of March 31, 2011, adjusted
    to reflect the issuance and sale of common units to the public
    at an assumed initial offering price of
    $      per common unit (the midpoint of
    the price range set forth on the cover of this prospectus), the
    other formation transactions described under
    Summary  Our Partnership Structure and
    Formation Transactions, and the application of the net
    proceeds from this offering as described under Use of
    Proceeds.    As of March 31, 2011Pro FormaOur


MemorialPredecessor


ProductionHistorical


Partners LP(In thousands)Long-term debt(1)

$
112,506


$Partners capital/net equity:Predecessor partners capital


108,039Common units held by purchasers in this offering


Common units held by Memorial Resource


Subordinated units held by Memorial Resource


General partner interest


Total partners capital/net equity(2)


108,039Total capitalization

$
220,545


$     (1)
    
    We intend to enter into a
    $      million revolving credit
    facility, approximately
    $      million of which will be
    available for borrowing upon the completion of the transactions
    described under Summary  Our Partnership
    Structure and Formation Transactions. After giving effect
    to the transactions described under Summary 
    Our Partnership Structure and Formation Transactions,
    including our expected borrowing of $130.0 million under
    our new revolving credit facility, we will have approximately
    $      million of borrowing
    capacity. For additional information on our new revolving credit
    facility, please read Managements Discussion and
    Analysis of Financial Condition and Results of
    Operations  Pro Forma Liquidity and Capital
    Resources  New Revolving Credit Facility.(2)
    
    A $1.00 increase or decrease in the assumed initial public
    offering price per common unit would increase or decrease,
    respectively, the net proceeds by approximately
    $      million, would result in a
    corresponding decrease or increase in the amount borrowed under
    our new revolving credit facility, and would change our total
    partners capital by approximately
    $      million, assuming the
    number of common units offered by us, as set forth on the cover
    page of this prospectus, remains the same.   59




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##### Table of Contents



DILUTION    Assumed initial offering price per common unit





$Pro forma as adjusted net tangible book value per unit before
    this offering(1)

$Increase in net tangible book value per unit attributable to
    purchasers in this offeringLess: Pro forma as adjusted net tangible book value per unit
    after this offering(2)Immediate dilution in net tangible book value per unit to
    purchasers in this offering(3)





$     (1)
    
    Determined by dividing the pro forma net tangible book value of
    our net assets immediately prior to the offering by the number
    of units
    (          
    common units
    and          
    subordinated units) to be issued to Memorial Resource as partial
    consideration for their contribution of the Partnership
    Properties to us and
    the          
    general partner units to be issued to our general partner.(2)
    
    Determined by dividing our pro forma as adjusted net tangible
    book value, after giving effect to the application of the
    expected net proceeds of this offering, by the total number of
    units to be outstanding after this offering
    (          common
    units,          subordinated
    units,
    and          general
    partner units).(3)
    
    If the assumed initial offering price were to increase or
    decrease by $1.00 per common unit, then dilution in pro forma as
    adjusted net tangible book value per unit would equal
    $      or
    $      , respectively. The information
    discussed above is illustrative only and will be adjusted based
    on the actual public offering price and other terms of this
    offering determined at pricing.    Units Acquired

Total ConsiderationNumber

Percent

$

Percent(In millions)General partner and its affiliates(1)(2)







%

$





%Purchasers in the offering(3)







%







%Total






100.0
%





$
100.0
%     (1)
    
    Upon the consummation of the transactions contemplated by this
    prospectus, and assuming the underwriters do not exercise their
    option to purchase additional common units, our general partner
    and its affiliates will
    own          
    common
    units,          subordinated
    units, and general partner units.(2)
    
    The assets contributed by Memorial Resource were recorded at
    historical cost in accordance with GAAP. Total consideration
    provided by affiliates of our general partner is equal to the
    pro forma net tangible book value of such assets as of
    March 31, 2011.(3)
    
    Total consideration is after deducting underwriting discounts
    and estimated offering expenses. 60




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##### Table of Contents



OUR CASH
    DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS  You should read the following discussion of our cash
    distribution policy in conjunction with specific assumptions
    included in this section. For more detailed information
    regarding the factors and assumptions upon which our cash
    distribution policy is based, please read
     Estimated Adjusted EBITDA for the Twelve
    Months Ending June 30, 2012 below. In addition, you
    should read Forward-Looking Statements and
    Risk Factors for information regarding statements
    that do not relate strictly to historical or current facts and
    certain risks inherent in our business.
  For additional information regarding our historical and pro
    forma operating results, you should refer to the audited
    historical combined financial statements of our predecessor as
    of and for the three years ended December 31, 2010, the
    unaudited historical combined financial statements of our
    predecessor for the three months ended March 31, 2011 and
    2010, and our unaudited pro forma combined financial statements
    for the year ended December 31, 2010 and the three months
    ended March 31, 2011, all included elsewhere in this
    prospectus.
 General  Rationale
    for Our Cash Distribution Policy
    Restrictions
    and Limitations on Cash Distributions and Our Ability to Change
    Our Cash Distribution Policy
    
    Our cash distribution policy may be subject to restrictions on
    distributions under our new revolving credit facility or other
    debt agreements that we may enter into in the future.
    Specifically, we anticipate that the agreement related to our
    new revolving credit facility will contain financial tests and
    covenants that we must satisfy. These financial ratios and
    covenants are described under the caption
    Managements Discussion and Analysis of Financial
    Condition and Results of Operations  Pro Forma
    Liquidity and Capital Resources  New Revolving Credit
    Facility. Should we be unable to satisfy these
    restrictions, or if a default occurs under our new revolving
    credit facility, we would be prohibited from making cash
    distributions to our unitholders notwithstanding our stated cash
    distribution policy.
    Our general partner will have the authority to establish
    reserves for the prudent conduct of our business and for future
    cash distributions to our unitholders, and the establishment of
    or increase in those reserves could result in a reduction in
    cash distributions to our unitholders from levels we currently
    anticipate under our stated distribution policy. Any
    determination to establish or increase reserves made by our
    general partner in good faith will be binding on the
    unitholders. We intend to reserve a portion of our cash
    generated from operations to fund our exploitation and
    development capital expenditures. 61




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Over a longer period of time, if our general partner does not
    set aside sufficient cash reserves or make sufficient cash
    expenditures to maintain our asset base, we will be unable to
    pay the minimum quarterly distribution from cash generated from
    operations and would therefore expect to reduce our
    distributions. We are unlikely to be able to sustain our current
    level of distributions without making accretive acquisitions or
    capital expenditures that maintain the current production levels
    of our oil and natural gas properties. Decreases in commodity
    prices from current levels will adversely affect our ability to
    pay distributions. If our asset base decreases and we do not
    reduce our distributions, a portion of the distributions may be
    considered a return of part of our unitholders investment
    in us as opposed to a return on our unitholders investment.  
    Prior to making any distribution on our common units, we will
    reimburse our general partner and its affiliates for all direct
    and indirect expenses they incur on our behalf. Our partnership
    agreement does not set a limit on the amount of expenses for
    which our general partner and its affiliates may be reimbursed.
    These expenses include salary, bonus, incentive compensation and
    other amounts paid to persons who perform services for us or on
    our behalf and expenses allocated to our general partner by its
    affiliates. Our partnership agreement provides that our general
    partner will determine in good faith the expenses that are
    allocable to us. The reimbursement of expenses and payment of
    fees, if any, to our general partner and its affiliates will
    reduce the amount of cash available to pay cash distributions to
    our unitholders.
    Although our partnership agreement requires us to distribute all
    of our available cash, our partnership agreement, including the
    provisions requiring us to make cash distributions contained
    therein, may be amended. Our partnership agreement may not be
    amended during the subordination period without the approval of
    our public common unitholders, other than in certain limited
    circumstances where no unitholder approval is required. However,
    our partnership agreement can be amended with the consent of our
    general partner and the approval of the holders of a majority of
    our outstanding common units (including common units that are
    held by Memorial Resource and its affiliates) after the
    subordination period has ended. Upon consummation of this
    offering, Memorial Resource will own our general partner and
    will control the voting of an aggregate of
    approximately     % of our outstanding
    common units and all of our subordinated units. Assuming we do
    not issue any additional common units and Memorial Resource does
    not transfer its common units, Memorial Resource will have the
    ability to amend our partnership agreement without the approval
    of any other unitholder once the subordination period ends.
    Even if our cash distribution policy is not modified or revoked,
    the amount of distributions we pay under our cash distribution
    policy and the decision to make any distribution is determined
    by our general partner, taking into consideration the terms of
    our partnership agreement, our new revolving credit facility and
    any other debt agreements we may enter into in the future.
    Under
    Section 17-607
    of the Delaware Revised Uniform Limited Partnership Act, we may
    not make a distribution to our unitholders if the distribution
    would cause our liabilities to exceed the fair value of our
    assets.
    We may lack sufficient cash to pay distributions to our
    unitholders due to a number of factors, including reductions in
    commodity prices, reductions in our oil and natural gas
    production, increases in our general and administrative
    expenses, principal and interest payments on our outstanding
    debt, tax expenses, working capital requirements and anticipated
    cash needs. For a discussion of additional factors that may
    affect our ability to pay distributions, please read Risk
    Factors.
    If and to the extent our cash available for distribution
    materially declines, we may reduce our quarterly distribution in
    order to service or repay our debt or fund growth capital
    expenditures.
    All available cash distributed by us on any date from any source
    will be treated as distributed from operating surplus until the
    sum of all available cash distributed since the closing of this
    offering equals the cumulative operating surplus from the
    closing of this offering through the end of the quarter
    immediately preceding that distribution. We anticipate that
    distributions from operating surplus will 62




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generally not represent a return of capital. However, operating
    surplus, as defined in our partnership agreement, includes
    certain components that represent non-operating sources of cash,
    including a $      million cash
    basket and working capital borrowings. Consequently, it is
    possible that distributions from operating surplus may represent
    a return of capital. For example, the
    $      million cash basket would
    allow us to distribute as operating surplus cash proceeds we
    receive from non-operating sources, such as assets sales,
    issuances of securities and long-term borrowings, which would
    represent a return of capital. Distributions representing a
    return of capital could result in a corresponding decrease in
    our asset base. Additionally, any cash distributed by us in
    excess of operating surplus will be deemed to be capital surplus
    under our partnership agreement. Our partnership agreement
    treats a distribution of capital surplus as the repayment of the
    initial unit price from this initial public offering, which is
    similar to a return of capital. Distributions from capital
    surplus could result in a corresponding decrease in our asset
    base. We do not anticipate that we will make any distributions
    from capital surplus. Please read Provisions of Our
    Partnership Agreement Relating to Cash Distributions 
    Operating Surplus and Capital Surplus and Provisions
    of Our Partnership Agreement Relating to Cash
    Distributions  Distributions from Capital
    Surplus  Effect of a Distribution from Capital
    Surplus.  Our
    Ability to Grow Depends on Our Ability to Access External Growth
    Capital
   Our
    Minimum Quarterly Distribution     63




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No Exercise of the Underwriters


Full Exercise of the UnderwritersOption to Purchase Additional Common Units


Option to Purchase Additional Common UnitsDistributions





DistributionsNumber of


One


Four


Number of


One


FourUnits


Quarter


Quarters


Units


Quarter


QuartersCommon units held by purchasers in this offering(1)





$



$







$



$Common units held by Memorial Resource and its affiliates(1)Subordinated unitsGeneral partner unitsTotal





$



$







$



$     (1)
    
    Does not include any common units that may be issued under the
    long-term incentive plan that our general partner is expected to
    adopt prior to the closing of this offering.       64




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##### Table of Contents




    Unaudited Pro Forma Available Cash for the Year Ended
    December 31, 2010 and Twelve Months Ended March 31,
    2011, in which we present the amount of cash we would have
    had available for distribution to our unitholders and our
    general partner for the year ended December 31, 2010 and
    the twelve months ended March 31, 2011, based on our
    unaudited pro forma financial statements. Our calculation of
    unaudited pro forma available cash in this table should only be
    viewed as a general indication of the amount of available cash
    that we might have generated had the transactions contemplated
    in this prospectus occurred in an earlier period.
    Estimated Cash Available for Distribution, in which
    we demonstrate our ability to generate the minimum Adjusted
    EBITDA necessary for us to have sufficient cash available for
    distribution to pay the full minimum quarterly distribution on
    all the outstanding units, including our general partner units,
    for the twelve months ending June 30, 2012. Unaudited
    Pro Forma Available Cash for the Year Ended December 31,
    2010 and Twelve Months Ended March 31, 2011   65




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Schedule K-1
   66




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##### Table of Contents



Memorial
    Production Partners LP
    Unaudited Pro Forma Cash Available for Distribution  Pro FormaYear Ended


Twelve Months EndedDecember 31, 2010


March 31, 2011(In thousands, except per unit data)Net income (loss)

$
12,303


$
2,546Interest expense


4,365



4,441Income tax expense


225



225Depreciation, depletion and amortization


34,772



32,655Impairment


9,509



7,818Accretion of asset retirement obligations


1,072



1,143Unrealized (gains) losses on derivative instruments


(2,674
)


4,927(Gain) loss on sale of properties






Unit-based compensation expense






Exploration costs


36



36Adjusted EBITDA(1)

$
59,608


$
53,791Less:Cash interest expense(2)

$
3,965


$
3,965Estimated average maintenance capital expenditures(3)


9,200



9,200Pro forma available cash(4)

$
46,443


$
40,626Pro forma annualized distributions per unit(5)

$



$Pro forma estimated annual cash distributions:Distributions on common units held by purchasers in this
    offering(5)

$



$Distributions on common units held by Memorial Resource and its
    affiliates(5)Distributions on subordinated units(5)Distributions on general partner units(5)Total estimated annual cash distributions(5)

$



$Excess (Shortfall)(5)

$



$Percent of minimum quarterly distributions payable to common
    unitholdersPercent of minimum quarterly distributions payable to
    subordinated unitholders     (1)
    
    Adjusted EBITDA is defined in Summary 
    Non-GAAP Financial Measures.(2)
    
    In connection with this offering, we intend to enter into a new
    $      million revolving credit
    facility under which we expect to incur approximately
    $130.0 million of borrowings upon the closing of this
    offering. If the net proceeds from this offering increase or
    decrease, then our borrowing under our new 67




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##### Table of Contents



revolving credit facility would correspondingly decrease or
    increase, respectively. The pro forma cash interest expense is
    based on $130.0 million of borrowings at an assumed
    weighted-average rate of 3.05%. If the interest rate used to
    calculate this interest were 1% higher or lower, our annual cash
    interest expense would increase or decrease, respectively, by
    $1.3 million. Likewise, a $1.00 increase or decrease in the
    assumed initial public offering price per common unit would
    result in a $      million
    decrease or increase in borrowings, respectively, and a
    $      million decrease or
    increase in interest expense, respectively.(3)
    
    Historically, our predecessor did not make a distinction between
    maintenance and growth capital expenditures. For purposes of the
    presentation of Unaudited Pro Forma Cash Available for
    Distribution, we have estimated that approximately
    $9.2 million of our predecessors capital expenditures
    were maintenance capital expenditures for the Partnership
    Properties for the respective period.(4)
    
    Does not reflect impact of $2.5 million of estimated
    incremental annual general and administrative expenses that we
    expect to incur associated with being a publicly traded
    partnership. Please read  Assumptions and
    Considerations  Capital Expenditures and
    Expenses.(5)
    
    The following table provides pro forma estimated annual cash
    distributions and the excess (shortfall) if the
    underwriters option to purchase additional common units is
    exercised in full.  Pro FormaYear Ended


Twelve Months EndedDecember 31, 2010


March 31, 2011(In thousands, except per unit data)Pro forma annualized distributions per unit

$



$Pro forma estimated annual cash distributions:Distributions on common units held by purchasers in this offering

$



$Distributions on common units held by Memorial Resource and its
    affiliatesDistributions on subordinated unitsDistributions on general partner unitsTotal estimated annual cash distributions

$



$Excess (Shortfall)

$



$   Estimated
    Adjusted EBITDA for the Twelve Months Ending June 30,
    2012     68




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Our
    Estimated Adjusted EBITDA
   69




---



##### Table of Contents




    Plus:  
    Interest expense, including realized and unrealized losses on
    interest rate derivative contracts;
    Income tax expense;
    Depreciation, depletion and amortization;
    Impairment of goodwill and long-lived assets (including oil and
    natural gas properties);
    Accretion of asset retirement obligations;
    Unrealized losses on commodity derivative contracts;
    Losses on sale of assets and other, net;
    Unit-based compensation expenses;
    Exploration costs; and
    Other non-routine items that we deem appropriate.  
    Less:  
    Interest income;
    Income tax benefit;
    Unrealized gains on commodity derivative contracts;
    Gains on sale of assets and other, net; and
    Other non-routine items that we deem appropriate. 70




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Memorial
    Production Partners LP
    Estimated Adjusted EBITDA  Forecasted for Twelve MonthsEnding June 30, 2012No Exercise


Full Exerciseof the


of theUnderwriters


UnderwritersOption to


Option toPurchase


PurchaseAdditional


AdditionalCommon Units


Common Units(In millions, except for perunit amounts)Operating revenue and realized commodity derivative gains
    (losses)(1)

$
100.7


$
100.7Less:Lease operating expenses


18.4



18.4Production and ad valorem taxes


8.9



8.9General and administrative expenses


5.0



5.0Depreciation, depletion and amortization


39.0



39.0Interest expense


3.8



3.8Net income excluding unrealized derivative gains (losses)

$
25.6


$
25.6Adjustments to reconcile net income excluding unrealized
    derivative gains (losses) to estimated Adjusted EBITDA:Add:Depreciation, depletion and amortization

$
39.0


$
39.0Interest expense


3.8



3.8Estimated Adjusted EBITDA

$
68.4


$
68.4Adjustments to reconcile estimated Adjusted EBITDA to cash
    available for distribution:Less:Cash interest expense(2)

$
3.8


$
3.8Estimated average maintenance capital expenditures(3)


9.2



9.2Estimated cash available for distribution

$
55.4


$
55.4Annualized minimum quarterly distribution per unit

$



$Estimated annual cash distributions:Distributions on common units held by purchasers in this offering

$



$Distributions on common units held by Memorial Resource and its
    affiliatesDistributions on subordinated unitsDistributions on general partner unitsTotal estimated annual cash distributions

$



$Excess cash available for distribution

$



$Minimum estimated Adjusted EBITDA:Estimated Adjusted EBITDA

$
68.4


$
68.4Less:Excess cash available for distributions(4)Minimum estimated Adjusted EBITDA

$



$  71




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##### Table of Contents



(1)
    
    Includes the forecasted effect of cash settlements of commodity
    derivative instruments.(2)
    
    In connection with this offering, we intend to enter into a new
    $      million revolving credit
    facility under which we expect to incur approximately
    $130.0 million of borrowings upon the closing of this
    offering. If the net proceeds from this offering increase or
    decrease, then our borrowing under our new revolving credit
    facility would correspondingly decrease or increase,
    respectively. The pro forma cash interest expense is based on
    $130.0 million of borrowings at an assumed weighted-average
    rate of 3.25%. If the interest rate used to calculate this
    interest were 1% higher or lower, our annual cash interest
    expense would increase or decrease, respectively, by
    $1.2 million. Likewise, a $1.00 increase or decrease in the
    assumed initial public offering price per common unit would
    result in a $      million
    decrease or increase in borrowings, respectively, and a
    $      million decrease or
    increase in interest expense, respectively.(3)
    
    In calculating the estimated cash available for distribution, we
    have included our estimated maintenance capital expenditures for
    the twelve months ending June 30, 2012. We expect to incur
    approximately $9.2 million of capital expenditures for the
    twelve months ending June 30, 2012 based on our reserve
    reports as of December 31, 2010, which amount incurred
    annually we also expect will enable us to maintain our targeted
    average net production from our assets of 49
    MMcfe/d
    through December 31, 2015.(4)
    
    We intend to retain any excess cash to repay indebtedness or for
    other general partnership purposes. Assumptions
    and Considerations     72




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##### Table of Contents



Operations
    and Revenue
  Production.
  ForecastedPro Forma Year


Pro Forma


Twelve MonthsEnded


Twelve Months


EndingDecember 31,


Ended


June 30,2010


March 31, 2011


2012(Unaudited)Annual Production:Oil (MBbl)


107



106



99NGLs (MBbl)


272



255



185Natural Gas (MMcf)


16,713



16,447



16,185Total (MMcfe)


18,985



18,613



17,887Average Net Production:Oil (MBbl/d)


0.3



0.3



0.3NGLs (MBbl/d)


0.8



0.7



0.5Natural Gas
    (MMcf/d)


45.8



45.1



44.3Total (MMcfe/d)


52.0



51.0



49.0    73




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##### Table of Contents



Prices.
  ForecastedPro Forma


Pro Forma


Twelve MonthsYear Ended


Twelve Months


EndingDecember 31,


Ended


June 30,2010


March 31, 2011


2012(Unaudited)Average oil sales prices:NYMEX-WTI oil price per Bbl

$
79.59


$
83.42


$
101.16Differential to NYMEX-WTI oil per Bbl

$
(5.24
)

$
(4.81
)

$
(4.25
)Realized oil sales price per Bbl (excluding cash settlements of
    derivatives)

$
74.35


$
78.61


$
96.91Realized oil sales price per Bbl (including cash settlements of
    derivatives)(1)(2)

$
74.35


$
78.61


$
96.06Average natural gas liquids sales prices:NYMEX-WTI oil price per Bbl

$
79.59


$
83.42


$
101.16Differential to NYMEX-WTI oil price per Bbl

$
(42.18
)

$
(45.54
)

$
(55.11
)Realized natural gas liquids sales price per Bbl (excluding cash
    settlements of derivatives)(1)(2)

$
37.41


$
37.88


$
46.05Realized natural gas liquids sales price per Bbl (including cash
    settlements of derivatives)(1)(2)

$
37.41


$
37.88


$
46.05Average natural gas sales prices:NYMEX-Henry Hub natural gas price per MMBtu

$
4.39


$
4.19


$
5.03Differential to NYMEX-Henry Hub natural gas

$
(0.22
)

$
(0.29
)

$
(0.06
)Realized natural gas sales price per Mcf (excluding cash
    settlements of derivatives)

$
4.17


$
3.90


$
4.97Realized natural gas sales price per Mcf (including cash
    settlements of derivatives)(1)(2)

$
4.17


$
3.90


$
5.11Total combined price (per Mcfe, excluding cash settlements of
    derivatives)

$
4.62


$
4.42


$
5.51Total combined price (per Mcfe, including cash settlements of
    derivatives)(1)(2)

$
4.62


$
4.42


$
5.63     (1)
    
    Average NYMEX futures prices for 2012 as reported on
    June 6, 2011. For a description of the effect of lower spot
    prices on cash available for distribution, please read
     Sensitivity Analysis  Commodity
    Price Changes.(2)
    
    Our pro forma realized prices do not include gains and losses on
    commodity derivative instruments. Because the commodity
    derivative contracts to be contributed to us have been
    commingled with the properties retained by our predecessor, the
    pro forma information associated with these commodity derivative
    contracts is not available by product type. We have given effect
    to the expected contribution to us at the closing of this
    offering of commodity derivative contracts covering 66% of our
    total forecasted production for the twelve months ending
    June 30, 2012.  Price Differentials.
 74




---



##### Table of Contents



Operating Area

MMBtu per McfSouth Texas


1.045East Texas


1.027Weighted Average


1.039         Oil


Natural GasOperating Area

Per Bbl


Per MMBtu


Per McfSouth Texas

$
(5.06
)

$
(0.15
)

$
0.08East Texas

$
(3.96
)

$
(0.43
)

$
(0.31
)Weighted Average

$
(4.25
)

$
(0.24
)

$
(0.06
)     Use of Commodity Derivative
    Contracts.
  Puts


Collars


SwapsWeighted AverageWeighted





Price





WeightedAverage





Floor


Ceiling





AverageOil (July 1, 2011  June 30, 2012)

Bbl


Price


Bbl


Price


Price


Bbl


PriceNYMEX  WTI


3,600


$
85.00



55,800


$
86.45


$
114.34







% of forecasted oil production


4
%






57
%% of total forecasted oil production


61
%   75




---



##### Table of Contents



Puts


Collars


SwapsWeighted AverageWeighted





Price





WeightedAverage





Floor


Ceiling





AverageNGL (July 1, 2011  June 30, 2012):

Bbl


Price


Bbl


Price


Price


Bbl


PriceMt. Belvieu Propane










14,400


$
52.50


$
66.78







Mt. Belvieu Butane










7,200


$
71.40


$
86.10







Mt. Belvieu Isobutane










4,800


$
71.40


$
89.04







Mt. Belvieu Gasoline










19,200


$
94.50


$
117.60







Total NGL Hedges










45,600


$
75.16


$
93.57







% of forecasted NGL production










25
%% of total forecasted NGL production


25
%   Puts


Collars


SwapsWeighted





Weighted Average Price





WeightedAverage





Floor


Ceiling





AverageNatural Gas (July 1, 2011  June 30, 2012):

MMBtu


Price


MMBtu


Price


Price


MMBtu


PriceNYMEX  Henry Hub


24,000


$
4.50



2,508,000


$
4.97


$
5.73



198,000


$
4.73TETCO South Texas Basis


1,920,000


$
4.41



1,980,000


$
4.90


$
6.34



600,000


$
5.73NGPL TexOk Basis










966,000


$
5.35


$
6.37



504,000


$
6.17Houston Ship Channel Basis










1,500,000


$
4.27


$
5.66



960,000


$
4.84Total Natural Gas Hedges


1,944,000


$
4.41



6,954,000


$
4.85


$
5.97



2,262,000


$
5.36% of forecasted natural gas production


12
%






43
%










14
%% of total forecasted natural gas production


69
%  76




---



##### Table of Contents



Operating Revenues and Realized Commodity Derivative
    Gains.
  ForecastedPro Forma


Pro Forma


Twelve MonthsYear Ended


Twelve Months


EndingDecember 31,


Ended


June 30,2010


March 31, 2011


2012(Unaudited)($ in millions)Oil:Oil revenues

$
7.9


$
8.3


$
9.6Oil derivative contracts gain (loss)(1)










(0.1
)Total

$
7.9


$
8.3


$
9.5NGLs:NGLs revenues

$
10.2


$
9.7


$
8.5NGLs derivative contracts gain (loss)(1)










Total

$
10.2


$
9.7


$
8.5Natural gas:Natural gas revenues

$
69.7


$
64.2


$
80.6Natural gas derivative contracts gain (loss)(1)










2.2Total

$
69.7


$
64.2


$
82.7Total:Operating Revenues

$
87.8


$
82.2


$
98.6Commodity derivative contracts gain (loss)(1)










2.1Operating revenue and realized commodity derivative contract
    gains

$
87.8


$
82.2


$
100.7     (1)
    
    Our pro forma realized prices do not include gains or losses on
    commodity derivative contracts. Because the commodity derivative
    contracts to be contributed to us have been commingled with the
    properties retained by our predecessor, the pro forma
    information associated with these commodity derivative contracts
    is not available by product type. We have given effect to the
    expected contribution to us at the closing of this offering of
    commodity derivative contracts covering 66% of our total
    forecasted production for the twelve months ending June 30,
    2012.  Capital
    Expenditures and Expenses
  Capital Expenditures.
   77




---



##### Table of Contents



Lease Operating Expenses.
  ForecastedPro Forma

Pro Forma

Twelve MonthsYear Ended

Twelve Months

EndingDecember 31,

Ended

June 30,2010

March 31, 2011

2012Lease operating expenses (in millions)

$
23
.1


$
23
.8


$
18
.4Lease operating expenses (per Mcfe)

$
1
.21


$
1
.28


$
1
.03     Production and Other Taxes.
  Pro Forma

ForecastedPro Forma

Twelve Months

Twelve MonthsYear Ended

Ended

EndingDecember 31, 2010

March 31, 2011

June 30, 2012($ in millions)Oil, natural gas and NGL revenues, excluding the effect of our
    commodity derivative contracts

$
87.8


$
82.2


$
98.6Production and ad valorem taxes

$
7.4


$
6.9


$
8.9Production and ad valorem taxes as a percentage of revenue


8.4
%


8.4
%


9.0
%     General and Administrative Expenses.
 78




---



##### Table of Contents



Depreciation, Depletion and Amortization
    Expense.
  Cash Interest Expense.
    Regulatory,
    Industry and Economic Factors
    
    There will not be any new federal, state or local regulation of
    portions of the energy industry in which we operate, or an
    interpretation of existing regulation, that will be materially
    adverse to our business;
    There will not be any major adverse change in commodity prices
    or the energy industry in general;
    Market, insurance and overall economic conditions will not
    change substantially; and
    We will not undertake any extraordinary transactions that would
    materially affect our cash flow.  Forecasted
    Distributions
     79




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##### Table of Contents



Sensitivity
    Analysis    Production
    Volume Changes
    Percentage of Forecasted Net Production90%


100%


110%(In millions, except per unit amounts)Forecasted net production:Oil (MBbl)


88.8



98.7



108.5NGLs (MBbl)


166.4



184.9



203.4Natural gas (MMcf)


14,566.8



16,185.4



17,803.9Total (MMcfe)


16,098.2



17,886.9



19,675.6Oil (Bbl/d)


242.6



269.6



296.5NGLs (Bbl/d)


454.7



505.3



555.8Natural gas (Mcf/d)


39,800.1



44,222.3



48,644.6Total (Mcfe/d)


43,984.3



48,871.4



53,758.5Forecasted prices:NYMEX-WTI oil price (per Bbl)

$
101.16


$
101.16


$
101.16Realized oil price (per Bbl) (excluding derivatives)

$
96.91


$
96.91


$
96.91Realized oil price (per Bbl) (including derivatives)

$
95.96


$
96.06


$
96.13NYMEX-WTI oil price (per Bbl)

$
101.16


$
101.16


$
101.16Realized natural gas liquids price (per Bbl) (excluding
    derivatives)

$
46.05


$
46.05


$
46.05Realized natural gas liquids price (per Bbl) (including
    derivatives)

$
46.05


$
46.05


$
46.05NYMEX-Henry Hub natural gas price (per MMBtu)

$
5.03


$
5.03


$
5.03Realized natural gas price (per Mcf) (excluding derivatives)

$
4.97


$
4.97


$
4.97Realized natural gas price (per Mcf) (including derivatives)

$
5.13


$
5.11


$
5.10 80




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##### Table of Contents



Percentage of Forecasted Net Production90%


100%


110%(In millions, except per unit amounts)Forecasted Adjusted EBITDA projection:Operating revenue

$
88.8


$
98.6


$
108.5Realized derivative gains (losses)


2.1



2.1



2.1Total revenue and realized derivative gains (losses)

$
90.9


$
100.7


$
110.6Oil and natural gas production expenses


(16.6
)


(18.4
)


(20.3
)Production and ad valorem taxes


(8.2
)


(8.9
)


(9.6
)General and administrative expenses


(5.0
)


(5.0
)


(5.0
)Estimated Adjusted EBITDA

$
61.1


$
68.4


$
75.7Minimum estimated Adjusted EBITDAExcess cash available for distribution

$



$



$   Commodity
    Price Changes
   81




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##### Table of Contents



(In millions of dollars, except per unit amounts)NYMEX-Henry Hub natural gas price (per MMBtu):

$
4.75


$
5.00


$
5.25


$
5.50NYMEX-WTI oil price (per Bbl):

$
90.00


$
100.00


$
110.00


$
120.00Forecasted net production:Oil (MBbl)


98.7



98.7



98.7



98.7NGLs (MBbl)


184.9



184.9



184.9



184.9Natural gas (MMcf)


16,185.4



16,185.4



16,185.4



16,185.4Total (MMcfe)


17,886.9



17,886.9



17,886.9



17,886.9Oil (Bbl/d)


269.6



269.6



269.6



269.6NGLs (Bbl/d)


505.3



505.3



505.3



505.3Natural gas (Mcf/d)


44,222.3



44,222.3



44,222.3



44,222.3Total (Mcfe/d)


48,871.4



48,871.4



48,871.4



48,871.4Forecasted prices:NYMEX-WTI oil price (per Bbl)

$
90.00


$
100.00


$
110.00


$
120.00Realized oil price (per Bbl) (excluding derivatives)

$
85.75


$
95.75


$
105.75


$
115.75Realized oil price (per Bbl) (including derivatives)

$
85.68


$
95.03


$
103.76


$
111.80NYMEX-WTI oil price (per Bbl)

$
90.00


$
100.00


$
110.00


$
120.00Realized natural gas liquids price (per Bbl) (excluding
    derivatives)

$
40.97


$
45.52


$
50.07


$
54.62Realized natural gas liquids price (per Bbl) (including
    derivatives)

$
41.35


$
45.52


$
49.85


$
53.01NYMEX-Henry Hub natural gas price (per MMBtu)

$
4.75


$
5.00


$
5.25


$
5.50Realized natural gas price (per Mcf) (excluding derivatives)

$
4.70


$
4.94


$
5.19


$
5.44Realized natural gas price (per Mcf) (including derivatives)

$
4.94


$
5.08


$
5.26


$
5.44Forecasted Adjusted EBITDA projection:Operating revenue

$
92.1


$
97.9


$
103.7


$
109.6Realized derivative gains (losses)


4.0



2.0



0.9



(0.6
)Total revenue and realized derivative gains (losses)

$
96.0


$
99.9


$
104.6


$
108.9Oil and natural gas production expenses


(18.4
)


(18.4
)


(18.4
)


(18.4
)Production and ad valorem taxes


(8.4
)


(8.8
)


(9.2
)


(9.6
)General and administrative expenses


(5.0
)


(5.0
)


(5.0
)


(5.0
)Estimated Adjusted EBITDA

$
64.2


$
67.7


$
71.9


$
75.9Minimum estimated Adjusted EBITDAExcess cash available for distribution

$



$



$



$   three-to-five
 82




---



##### Table of Contents



83




---



##### Table of Contents



PROVISIONS
    OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH
    DISTRIBUTIONS   Distributions
    of Available Cash  General
    Definition
    of Available Cash
    
    less, the amount of cash reserves established by our general
    partner at the date of determination of available cash for the
    quarter to:  
    provide for the proper conduct of our business, which could
    include, but is not limited to, amounts reserved for capital
    expenditures, working capital and operating expenses;
    comply with applicable law, any of our debt instruments or other
    agreements; or
    provide funds for distributions to our unitholders (including
    our general partner) for any one or more of the next four
    quarters (provided that our general partner may not establish
    cash reserves for future distributions on our common and
    subordinated units unless it determines that the establishment
    of reserves will not prevent us from distributing the minimum
    quarterly distribution on all common units and any cumulative
    arrearages on such common units for such quarter);  
    plus, if our general partner so determines, all or a portion of
    cash on hand on the date of determination of available cash for
    the quarter resulting from borrowing (including working capital
    borrowings) made after the end of the quarter.      Intent
    to Distribute the Minimum Quarterly Distribution
   84




---



##### Table of Contents



General
    Partner Interest and Incentive Distribution Rights
  ,
   Operating
    Surplus and Capital Surplus  General
    Operating
    Surplus
    
    $      million (as described
    below); plus
    all of our cash receipts after the closing of this offering,
    excluding cash from interim capital transactions, which include
    the following:  
    borrowings (including sales of debt securities) that are not
    working capital borrowings;
    sales of equity interests; and
    sales or other dispositions of assets outside the ordinary
    course of business;  plus
  
    working capital borrowings made after the end of the period but
    on or before the date of determination of operating surplus for
    the period; plus 85




---



##### Table of Contents




    cash distributions paid (including incremental incentive
    distributions) on equity issued to finance all or a portion of
    the construction, replacement, acquisition, development or
    improvement of a capital improvement or replacement of a capital
    asset (such as reserves or equipment) in respect of the period
    beginning on the date that we enter into a binding obligation to
    commence the construction, replacement, acquisition, development
    or improvement of a capital improvement, construction,
    replacement, acquisition, development or improvement of a
    capital asset and ending on the earlier to occur of the date the
    capital improvement or capital asset begins producing in paying
    quantities or is placed into service, as applicable, and the
    date that it is abandoned or disposed of; plus
    cash distributions paid (including incremental incentive
    distributions) on equity issued to pay the construction period
    interest on debt incurred (including periodic net payments under
    related interest rate swap arrangements), or to pay construction
    period distributions on equity issued, to finance the capital
    improvements or capital assets referred to above; less
    all of our operating expenditures (as described below) after the
    closing of this offering and the completion of the formation
    transactions; less
    the amount of cash reserves established by our general partner
    to provide funds for future operating expenditures; less
    all working capital borrowings not repaid within twelve months
    after having been incurred, or repaid within such twelve month
    period with the proceeds of additional working capital
    borrowings; less
    any cash loss realized on disposition of an investment capital
    expenditure.        
    repayment of working capital borrowings previously deducted from
    operating surplus pursuant to the provision described in the
    penultimate bullet point of the description of operating surplus
    above when such repayment actually occurs; 86




---



##### Table of Contents




    payments (including prepayments and prepayment penalties) of
    principal of and premium on indebtedness, other than working
    capital borrowings;
    growth capital expenditures;
    actual maintenance capital expenditures (as discussed in further
    detail below);
    investment capital expenditures;
    payment of transaction expenses relating to interim capital
    transactions;
    distributions to our partners; or
    repurchases of equity interests except to fund obligations under
    employee benefit plans. Capital
    Surplus    
    borrowings (including sales of debt securities) other than
    working capital borrowings;
    sales of our equity interests; and
    sales or other dispositions of assets outside the ordinary
    course of business.  Characterization
    of Cash Distributions
   Capital
    Expenditures     87




---



##### Table of Contents




    it will reduce the risk that maintenance capital expenditures in
    any one quarter will be large enough to render operating surplus
    less than the minimum quarterly distribution to be paid on all
    the units for the quarter;
    it will increase our ability to distribute as operating surplus
    cash we receive from non-operating sources;
    in quarters where estimated maintenance capital expenditures
    exceed actual maintenance capital expenditures, it will be more
    difficult for us to raise our distribution above the minimum
    quarterly distribution, because the amount of estimated
    maintenance capital expenditures will reduce the amount of cash
    available for distribution to our unitholders, even in quarters
    where there are no corresponding actual capital expenditures;
    conversely, the use of estimated maintenance capital
    expenditures in calculating operating surplus will have the
    opposite effect for quarters in which actual maintenance capital
    expenditures exceed our estimated maintenance capital
    expenditures; and
    it will reduce the likelihood that a large maintenance capital
    expenditure during a particular quarter will prevent our general
    partners affiliates from being able to convert some or all
    of their subordinated units to common units since the effect of
    an estimate is to spread the expected expense over several
    periods, thereby mitigating the effect of the actual payment of
    the expenditure on any single period.       88




---



##### Table of Contents



Subordination
    Period  General
    Expiration
    of the Subordination Period
    
    distributions of available cash from operating surplus on each
    of the outstanding common units, subordinated units, and general
    partner units equaled or exceeded, in the aggregate, the minimum
    quarterly distributions payable with respect to a period of
    twelve consecutive quarters immediately preceding that date;
    the adjusted operating surplus (as defined below)
    generated during the twelve consecutive quarters immediately
    preceding that date equaled or exceeded, in the aggregate, the
    sum of the minimum quarterly distributions on all of the
    outstanding common units, subordinated units, and general
    partner units payable with respect to such period on a fully
    diluted basis; and
    there are no arrearages in payment of the minimum quarterly
    distribution on the common units.  Early
    Conversion of Subordinated Units
    
    distributions of available cash from operating surplus on each
    of the outstanding common units, subordinated units and the
    general partner units equaled or exceeded
    $      (125% of the minimum quarterly
    distribution), and the related distribution on the incentive
    distribution rights was made, for the four-quarter period
    immediately preceding that date; 89




---



##### Table of Contents




    the adjusted operating surplus generated during the
    four-quarter period immediately preceding that date equaled or
    exceeded the sum of a distribution of
    $     (125% of the minimum quarterly
    distribution) on all of the outstanding common units and
    subordinated units on a fully diluted basis and the related
    distributions on the general partner units and the incentive
    distribution rights during those periods; and
    there are no arrearages in payment of the minimum quarterly
    distribution on the common units.  Effect
    of the Expiration of the Subordination Period
    Effect
    of the Expiration of the Subordination Period Following Removal
    of our General Partner
    
    the subordination period will end and each subordinated unit
    will immediately convert into one common unit;
    any existing arrearages in payment of the minimum quarterly
    distribution on the common units will be extinguished; and
    our general partner will have the right to convert its general
    partner units into common units or to receive cash in exchange
    for such general partner units at the equivalent common unit
    fair market value.  Adjusted
    Operating Surplus
    
    operating surplus generated with respect to that period
    (excluding any amounts attributable to the items described in
    the first bullet point under  Operating Surplus
    and Capital Surplus  Operating Surplus);
    less
    any net increase in working capital borrowings with respect to
    that period; less
    any net decrease in cash reserves for operating expenditures
    with respect to that period not relating to an operating
    expenditure made with respect to that period; plus
    any net decrease in working capital borrowings with respect to
    that period; plus
    any net increase in cash reserves for operating expenditures
    with respect to that period required by any debt instrument for
    the repayment of principal, interest or premium; plus
    any net decrease made in subsequent periods in cash reserves for
    operating expenditures initially established with respect to
    such period to the extent such decrease results in a reduction
    of adjusted operating surplus in subsequent periods pursuant to
    the third bullet point above. 90




---



##### Table of Contents



Distributions
    of Available Cash from Operating Surplus During the
    Subordination Period    
    first, 99.9% to the common unitholders, pro rata, and
    0.1% to our general partner, until we distribute for each
    outstanding common unit an amount equal to the minimum quarterly
    distribution for that quarter;
    second, 99.9% to the common unitholders, pro rata, and
    0.1% to our general partner, until we distribute for each
    outstanding common unit an amount equal to any arrearages in
    payment of the minimum quarterly distribution on the common
    units for any prior quarters during the subordination period;
    third, 99.9% to the subordinated unitholders, pro rata,
    and 0.1% to our general partner, until we distribute for each
    subordinated unit an amount equal to the minimum quarterly
    distribution for that quarter; and
    thereafter, in the manner described in
     General Partner Interest and Incentive
    Distribution Rights below.   Distributions
    of Available Cash from Operating Surplus After the Subordination
    Period    
    first, 99.9% to all unitholders, pro rata, and 0.1% to
    our general partner, until we distribute for each outstanding
    unit an amount equal to the minimum quarterly distribution for
    that quarter; and
    thereafter, in the manner described in
     General Partner Interest and Incentive
    Distribution Rights below.   General
    Partner Interest and Incentive Distribution Rights     91




---



##### Table of Contents




    we have distributed available cash from operating surplus to the
    common and subordinated unitholders in an amount equal to the
    minimum quarterly distribution; and
    we have distributed available cash from operating surplus on
    outstanding common units in an amount necessary to eliminate any
    cumulative arrearages in payment of the minimum quarterly
    distribution;    
    first, 99.9% to all unitholders, pro rata, and 0.1% to
    our general partner, until each unitholder receives a total of
    $      per unit for that quarter (the
    first target distribution);
    second, 85.0% to all unitholders, pro rata, and 15.0% to
    our general partner, until each unitholder receives a total of
    $      per unit for that quarter (the
    second target distribution); and
    thereafter, 75.0% to all unitholders, pro rata, and 25.0%
    to our general partner. Percentage
    Allocations of Available Cash from Operating Surplus    Total Quarterly

Marginal Percentage Interest in DistributionsDistribution per Unit

Unitholders

General PartnerMinimum Quarterly Distribution

$




99.9
%


0.1
%First Target Distribution

above $
up to $



99.9
%


0.1
%Second Target Distribution

above $
up to $



85.0
%


15.0
%Thereafter

above $




75.0
%


25.0
%  General
    Partners Right to Reset Incentive Distribution
    Levels   92




---



##### Table of Contents




    first, 99.9% to all unitholders, pro rata, and 0.1% to
    our general partner, until each unitholder receives an amount
    equal to 115% of the reset minimum quarterly distribution for
    that quarter;
    second, 85.0% to all unitholders, pro rata, and 15.0% to
    our general partner, until each unitholder receives an amount
    per unit equal to 125% of the reset minimum quarterly
    distribution for the quarter; and
    thereafter, 75.0% to all unitholders, pro rata, and 25.0%
    to our general partner.    Quarterly

Marginal Percentage Interest in

Quarterly Distribution perDistribution per Unit

Distributions

Unit Following HypotheticalPrior to Reset

Unitholders

General Partner

ResetMinimum quarterly distribution


$



99.9
%


0.1
%

$First target distribution


up to $



99.9
%


0.1
%

up
    to $  (1)Second target distribution


above $  up to $



85.0
%


15.0
%

above $  (1)  up to $     (2)Thereafter


above $



75.0
%


25.0
%

above
    $     (2)     (1)
    
    This amount is 115.0% of the hypothetical reset minimum
    quarterly distribution.(2)
    
    This amount is 125.0% of the hypothetical reset minimum
    quarterly distribution. 93




---



##### Table of Contents



CashQuarterly


Distributions to


Cash Distributions to General Partner Prior to ResetDistribution per


Common








IncentiveUnit Prior to


Unitholders


Common


0.1% General


Distribution





TotalReset


Prior to Reset


Units


Partner Interest


Rights


Total


DistributionsMinimum quarterly distribution


$


$



$



$



$



$



$First target distribution


up to $







Second target distribution


above $  up to $







Thereafter


above $







$



$



$



$



$



$     CashQuarterly


Distributions to


Cash Distributions to General Partner After ResetDistribution per


Common








IncentiveUnit Prior to


Unitholders


Common


0.1% General


Distribution





TotalReset


Prior to Reset


Units


Partner Interest


Rights


Total


DistributionsMinimum quarterly distribution


$


$



$



$



$



$



$First target distribution


up to $























Second target distribution


above $  up to $























Thereafter


above $























$



$



$



$



$



$    Distributions
    from Capital Surplus  How
    Distributions from Capital Surplus Will Be Made
    
    First, 99.9% to all unitholders, pro rata, and 0.1% to
    our general partner, until the minimum quarterly distribution is
    reduced to zero, as described below; 94




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##### Table of Contents




    Second, 99.9% to the common unitholders, pro rata, and
    0.1% to our general partner, until we distribute for each common
    unit, an amount of available cash from capital surplus equal to
    any unpaid arrearages in payment of the minimum quarterly
    distribution on the common units; and
    Thereafter, we will make all distributions of available
    cash from capital surplus as if they were from operating surplus.    Effect
    of a Distribution from Capital Surplus
     Adjustment
    to the Minimum Quarterly Distribution and Target Distribution
    Levels    
    the minimum quarterly distribution;
    target distribution levels;
    the unrecovered initial unit price; and
    the number of common units into which a subordinated unit is
    convertible.  two-for-one
   95




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##### Table of Contents



non-U.S. income
 Distributions
    of Cash Upon Liquidation  General
      Manner
    of Adjustments for Gain
    
    first, to our general partner and the holders of units
    who have negative balances in their capital accounts to the
    extent of and in proportion to those negative balances;
    second, 99.9% to the common unitholders, pro rata, and
    0.1% to our general partner, until the capital account for each
    common unit is equal to the sum of: (1) the unrecovered
    initial unit price; (2) the amount of the minimum quarterly
    distribution for the quarter during which our liquidation
    occurs; and (3) any unpaid arrearages in payment of the
    minimum quarterly distribution;
    third, 99.9% to the subordinated unitholders, pro rata,
    and 0.1% to our general partner, until the capital account for
    each subordinated unit is equal to the sum of: (1) the
    unrecovered initial unit price; and (2) the amount of the
    minimum quarterly distribution for the quarter during which our
    liquidation occurs;
    fourth, 99.9% to all unitholders, pro rata, and 0.1% to
    our general partner, until we allocate under this paragraph an
    amount per unit equal to: (1) the sum of the excess of the
    first target distribution per unit over the minimum quarterly
    distribution per unit for each quarter of our existence; less
    (2) the cumulative amount per unit of any distributions of
    available cash from operating surplus in excess of the minimum
    quarterly distribution per unit that we distributed 99.9% to the
    unitholders, pro rata, and 0.1% to our general partner, for each
    quarter of our existence; 96




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##### Table of Contents




    fifth, 85.0% to all unitholders, pro rata, and 15.0% to
    our general partner, until we allocate under this paragraph an
    amount per unit equal to: (1) the sum of the excess of the
    second target distribution per unit over the first target
    distribution per unit for each quarter of our existence; less
    (2) the cumulative amount per unit of any distributions of
    available cash from operating surplus in excess of the first
    target distribution per unit that we distributed 85.0% to the
    unitholders, pro rata, and 15.0% to our general partner for each
    quarter of our existence; and
    thereafter, 75.0% to all unitholders, pro rata, and 25.0%
    to our general partner.      Manner
    of Adjustments for Losses
    
    first, 99.9% to holders of subordinated units in
    proportion to the positive balances in their capital accounts
    and 0.1% to our general partner, until the capital accounts of
    the subordinated unitholders have been reduced to zero;
    second, 99.9% to the holders of common units in
    proportion to the positive balances in their capital accounts
    and 0.1% to our general partner, until the capital accounts of
    the common unitholders have been reduced to zero; and
    thereafter, 100.0% to our general partner.    Adjustments
    to Capital Accounts
   97




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SELECTED
    HISTORICAL AND PRO FORMA FINANCIAL DATA      
    adjustments to reflect the acquisitions of oil and natural gas
    properties consummated in June 2010, April 2011, and May 2011 by
    our predecessor;
    the contribution by Memorial Resource and certain of its
    subsidiaries, including our predecessor, to us of the
    Partnership Properties in exchange
    for          
    common
    units,          subordinated
    units and $      million in cash
    and the issuance to our general partner
    of          
    general partner units, representing a 0.1% general partner
    interest in us, and all of our incentive distribution rights;
    the issuance and sale by us to the public
    of          
    common units in this offering and the application of the net
    proceeds as described in Use of Proceeds; and
    our borrowing of approximately $130.0 million under our new
    $      million revolving credit
    facility and the application of the net proceeds as described in
    Use of Proceeds. If the net proceeds from this
    offering increase or decrease, then our borrowing under the new
    revolving credit facility would correspondingly decrease or
    increase, respectively.   98




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##### Table of Contents



Memorial ProductionPartners LPPro FormaThreeOur Predecessor


Year


MonthsThree Months Ended


Ended


EndedYear Ended December 31,


March 31,


December 31,


March 31,2006


2007


2008


2009


2010


2010


2011


2010


2011(Unaudited)











(Unaudited)


(Unaudited)(In thousands)Statement of Operations Data:RevenuesOil and natural gas sales

$
112


$
11,949


$
49,313


$
24,541


$
37,308


$
7,879


$
11,641


$
87,762


$
20,648Other income


21



153



622



319



1,433



67



103



1,404



99Total revenues


133



12,102



49,935



24,860



38,741



7,946



11,744



89,166



20,747Costs and expenses:Lease operating


156



2,873



8,843



11,207



13,974



2,220



5,170



23,052



6,685Exploration










374



2,690



39











36



Production and ad valorem taxes


7



1,113



3,127



1,464



2,112



509



693



7,387



1,703Depreciation, depletion and amortization


233



18,144



12,353



15,226



20,066



4,352



4,450



34,772



7,026Impairment of proved oil and natural gas properties


1,430







14,166



3,480



11,800



1,691







9,509



General and administrative


1,390



2,937



3,835



4,811



6,116



1,108



1,474



5,819



1,399Accretion


1



319



224



320



663



64



210



1,072



276(Gain) loss on derivative instruments






734



(9,815
)


(10,834
)


(10,264
)


(6,636
)


703



(10,264
)


703Gain on sale of properties










(7,395
)


(7,851
)


(1
)






(8
)






Other, net


(508
)


744







304



890











890



Total costs and expenses


2,709



26,864



25,712



20,817



45,395



3,308



12,692



72,273



17,792Operating income (loss)


(2,576
)


(14,762
)


24,223



4,043



(6,654
)


4,638



(948
)


16,893



2,955Interest expense


(7
)


(1,135
)


(3,138
)


(2,937
)


(4,438
)


(606
)


(1,035
)


(4,365
)


(1,092
)Income (loss) before income taxes


(2,583
)


(15,897
)


21,085



1,106



(11,092
)


4,032



(1,983
)


12,528



1,863Income tax expense


















(225
)










(225
)


Net income (loss)

$
(2,583
)

$
(15,897
)

$
21,085


$
1,106


$
(11,317
)

$
4,032


$
(1,983
)

$
12,303


$
1,863Cash Flow Data:Net cash provided by operating activities

$
(1,282
)

$
6,742


$
32,838


$
12,672


$
20,288


$
3,935


$
2,999Net cash (used in) investing activities


(6,538
)


(97,416
)


(45,547
)


(24,947
)


(116,687
)


(10,601
)


(7,898
)Net cash provided by financing activities


8,500



93,196



11,619



15,989



96,756



9,434



1,375Other Financial Data:Adjusted EBITDA









$
33,971


$
24,340


$
23,239


$
5,042


$
5,602


$
59,608


$
12,155   MemorialProductionPartners LPOur Predecessor


Pro FormaAs of


As ofYear Ended December 31,


March 31,


March 31,2006


2007


2008


2009


2010


2011


2011(Unaudited)








(Unaudited)(In thousands)Balance Sheet Data:Working capital (deficit)

$
1,107


$
(1,684
)

$
(966
)

$
9,494


$
4,116


$
2,490


$
1,318Total assets


6,565



99,021



145,529



146,153



248,540



245,042



435,107Total debt


3,500



46,726



62,536



61,784



115,428



112,584



130,000Partners capital


2,416



36,488



54,576



72,988



105,801



108,039



278,543  99




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##### Table of Contents



MANAGEMENTS
    DISCUSSION AND ANALYSIS OF
    FINANCIAL CONDITION AND RESULTS OF OPERATIONS  This Managements Discussion and Analysis of Financial
    Condition and Results of Operations contains the following
    information:
  
    a discussion of our business on a pro forma basis,
    including:  
    a general overview of our properties;
    our results of operations;
    our liquidity and capital resources; and
    our quantitative and qualitative disclosures about market
    risk; and  
    a discussion of our predecessors business on a
    historical basis, including:  
    our predecessors results of operations;
    our predecessors liquidity and capital resources;
    and
    our predecessors quantitative and qualitative
    disclosures about market risk.  The following Managements Discussion and Analysis of
    Financial Condition and Results of Operations should be read in
    conjunction with the Selected Historical and Pro Forma
    Financial Data and the accompanying financial statements
    and related notes included elsewhere in this prospectus. Unless
    otherwise indicated, all references to financial or operating
    data on a pro forma basis give effect to the transactions
    described under Summary  Our Partnership
    Structure and Formation Transactions and in the unaudited
    pro forma combined financial statements included elsewhere in
    this prospectus. The following discussion contains
    forward-looking statements that reflect our future plans,
    estimates, beliefs and expected performance. The forward-looking
    statements are dependent upon events, risks and uncertainties
    that may be outside our control. Our actual results could differ
    materially from those discussed in these forward-looking
    statements. Factors that could cause or contribute to such
    differences include, but are not limited to, market prices for
    oil and natural gas, production volumes, estimates of proved
    reserves, capital expenditures, economic and competitive
    conditions, regulatory changes and other uncertainties, as well
    as those factors discussed below and elsewhere in this
    prospectus, particularly in Risk Factors and
    Forward-Looking Statements, all of which are
    difficult to predict. In light of these risks, uncertainties and
    assumptions, the forward-looking events discussed may not
    occur.
 Overview    Our
    Properties
   100




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##### Table of Contents



reserve-to-production
  Memorial
    Resources Retained Properties
    How We
    Conduct Our Business and Evaluate Our Operations
    
    production volumes;
    realized prices on the sale of oil and natural gas, including
    the effect of our derivative contracts;
    lease operating expenses;
    general and administrative expenses; and
    Adjusted EBITDA.  Production
    Volumes
    Realized
    Prices on the Sale of Oil and Natural Gas
  Factors Affecting the Sales Price of Oil and Natural
    Gas.
  Natural Gas. 2 2 2 2 2
   101




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Oil.
        Commodity Derivative Contracts. three-to-five
   102




---



##### Table of Contents



Year Ending December 31,2011


2012


2013


2014


2015Natural Gas Derivative Contracts:Swap contracts:Volume (MMBtu/d)


5,682



6,164



4,932







Weighted-average fixed price

$
5.37


$
5.32


$
5.24


$



$
Collar contracts:Volume (MMBtu/d)


12,225



20,311



19,463



3,945



2,630Weighted-average ceiling price

$
6.27


$
5.91


$
5.83


$
6.31


$
6.75Weighted-average floor price

$
5.02


$
4.79


$
4.75


$
5.08


$
5.25Put options:Volume (MMBtu/d)


8,285



2,295











Weighted-average floor price

$
4.30


$
4.80


$



$



$
Total natural gas volumes hedged (MMBtu/d):


26,192



28,770



24,395



3,945



2,630Oil Derivative Contracts:Collar contracts:Volume (Bbl/d)


114



148



156



105



Weighted-average ceiling price

$
110.87


$
115.12


$
116.94


$
117.72


$
Weighted-average floor price

$
84.81


$
86.67


$
87.16


$
90.00


$
Put options:Volume (Bbl/d)


10















Weighted-average floor price

$
85.00


$



$



$



$
Natural Gas Liquids Derivative Contracts:Collar contracts:Volume (Bbl/d)


62



125











Weighted-average ceiling price

$
93.57


$
93.57


$



$



$
Weighted-average floor price

$
75.16


$
75.16


$



$



$
   Lease Operating Expenses.
   103




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Production and Ad Valorem Taxes.
  General and Administrative Expenses. Schedule K-1
  Adjusted
    EBITDA
    
    Plus:  
    Interest expense, including realized and unrealized losses on
    interest rate derivative contracts;
    Income tax expense;
    Depreciation, depletion and amortization;
    Impairment of goodwill and long-lived assets (including oil and
    natural gas properties);
    Accretion of asset retirement obligations;
    Unrealized losses on commodity derivative contracts;
    Losses on sale of assets and other, net;
    Unit-based compensation expenses;
    Exploration costs; and
    Other non-routine items that we deem appropriate. 104




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##### Table of Contents




    Less:  
    Interest income;
    Income tax benefit;
    Unrealized gains on commodity derivative contracts;
    Gains on sale of assets and other, net; and
    Other non-routine items that we deem appropriate.      
    our operating performance as compared to that of other companies
    and partnerships in our industry, without regard to financing
    methods, capital structure or historical cost basis; and
    the ability of our assets to generate cash sufficient to pay
    interest costs, support our indebtedness, and make distributions
    on our units.    Outlook
     105




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##### Table of Contents



106




---



##### Table of Contents



Historical
    and Pro Forma Financial and Operating Data    Our Predecessor


Memorial Production Partners LP Pro FormaThree





ThreeMonths





MonthsEnded


Year Ended


EndedYear Ended December 31,


March 31,


December 31,


March 31,2008


2009


2010


2010


2011


2010


2011(Unaudited)


(Unaudited)Revenues (in thousands):Oil and natural gas sales

$
49,313


$
24,541


$
37,308


$
7,879


$
11,641


$
87,762


$
20,648Other income


622



319



1,433



67



103



1,404



99Total revenues

$
49,935


$
24,860


$
38,741


$
7,946


$
11,744


$
89,166


$
20,747Costs and expenses (in thousands):Lease operating


8,843



11,207



13,974



2,220



5,170



23,052



6,685Exploration


374



2,690



39











36



Production and ad valorem taxes


3,127



1,464



2,112



509



693



7,387



1,703Depreciation, depletion and amortization


12,353



15,226



20,066



4,352



4,450



34,772



7,026Impairment of proved oil and natural gas properties


14,166



3,480



11,800



1,691







9,509



General and administrative


3,835



4,811



6,116



1,108



1,474



5,819



1,399Accretion


224



320



663



64



210



1,072



276(Gain) loss on derivative instruments


(9,815
)


(10,834
)


(10,264
)


(6,636
)


703



(10,264
)


703Gain on sale of properties


(7,395
)


(7,851
)


(1
)






(8
)






Other, net






304



890











890



Total costs and expenses


25,712



20,817



45,395



3,308



12,692



72,273



17,792Operating income (loss)


24,223



4,043



(6,654
)


4,638



(948
)


16,893



2,955Interest expense


(3,138
)


(2,937
)


(4,438
)


(606
)


(1,035
)


(4,365
)


(1,092
)Income (loss) before income taxes


21,085



1,106



(11,092
)


4,032



(1,983
)


12,528



1,863Income tax expense










(225
)










(225
)


Net income (loss)

$
21,085


$
1,106


$
(11,317
)

$
4,032


$
(1,983
)

$
12,303


$
1,863Oil and natural gas revenue (in thousands):Oil sales

$
5,886


$
3,521


$
3,438


$
740


$
1,472


$
7,933


$
2,539NGL sales


1,559



924



1,404



345



278



10,177



2,434Natural gas sales


41,868



20,096



32,466



6,794



9,891



69,652



15,675Total oil and natural gas revenue

$
49,313


$
24,541


$
37,308


$
7,879


$
11,641


$
87,762


$
20,648Production:Oil (MBbls)


59



61



45



10



16



107



28NGLs (MBbls)


83



33



34



8



5



272



56Natural gas (MMcf)


4,719



5,282



7,314



1,224



2,266



16,713



3,897Total (MMcfe)


5,569



5,847



7,792



1,330



2,395



18,985



4,399Average net production (MMcfe/d)


15.2



16.0



21.3



14.8



26.6



52.0



48.8Average sales price:Oil (per Bbl)

$
100.58


$
58.01


$
75.81


$
74.33


$
91.28


$
74.35


$
90.11NGLs (per Bbl)

$
18.76


$
27.61


$
41.02


$
44.30


$
52.09


$
37.41


$
43.76Natural gas (per Mcf)

$
8.87


$
3.80


$
4.44


$
5.55


$
4.36


$
4.17


$
4.02Total (per Mcfe)

$
8.86


$
4.20


$
4.79


$
5.92


$
4.86


$
4.62


$
4.69Average unit costs per Mcfe:Lease operating expenses

$
1.59


$
1.92


$
1.79


$
1.67


$
2.16


$
1.21


$
1.52Production and ad valorem taxes

$
0.56


$
0.25


$
0.27


$
0.38


$
0.29


$
0.39


$
0.39General and administrative expenses

$
0.69


$
0.82


$
0.78


$
0.83


$
0.62


$
0.31


$
0.32Depreciation, depletion and amortization

$
2.22


$
2.60


$
2.58


$
3.27


$
1.86


$
1.83


$
1.60  107




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##### Table of Contents



Background
    Information Regarding Our Predecessor, the Partnership
    Properties, and Related Financial Data
   Pro Forma
    Results of Operations  Factors
    Affecting the Comparability of the Pro Forma Results of Our
    Partnership to the Historical Financial Results of Our
    Predecessor
    
    Our predecessor completed its acquisition of certain properties
    from Forest Oil in June 2010. Prior to such time, the estimated
    proved reserves associated with and the results of operations
    from those acquired assets were not included in our
    predecessors results of operations prior to the date of
    acquisition. The Forest Oil properties acquired by our
    predecessor are included in the Partnership Properties and
    represent 50 Bcfe, or approximately 15% of our pro forma
    total estimated proved reserves, as of December 31, 2010.
    Our predecessor completed its acquisition of certain properties
    from BP in May 2011. The estimated proved reserves associated
    with and the results of operations from those acquired assets
    were not included in our predecessors historical results
    of operations through May 31, 2011. The BP America
    properties acquired by our predecessor are included in the
    Partnership Properties and represent 47 Bcfe, or
    approximately 15% of our pro forma total estimated proved
    reserves, as of December 31, 2010.
    The Partnership Properties will include property interests
    contributed to us by WHT, all of which property interests were
    acquired by WHT in April 2011. Those properties being
    contributed represent 113 Bcfe, or approximately 35% of our
    pro forma total estimated proved reserves, as of
    December 31, 2010.
    Our predecessor pays a management fee to the Funds pursuant to
    its operating agreement. We are not obligated to pay such a
    management fee, and therefore our pro forma results of
    operations are not directly comparable to our predecessors
    with respect to this fee.
    Our predecessor uses commodity derivative contracts to manage
    price fluctuations. Upon the closing of this offering, we will
    enter into derivative contracts to manage price fluctuations and
    our predecessor will contribute to us certain commodity
    derivative contracts entered into in connection with its
    ownership of the Partnership Properties, which will not comprise
    all commodity derivative contracts entered into by our
    predecessor. Pro Forma
    Liquidity and Capital Resources   108




---



##### Table of Contents



three-to-five
        and/or
  Capital
    Expenditures
     109




---



##### Table of Contents



New
    Revolving Credit Facility
          Commodity
    Derivative Contracts
   110




---



##### Table of Contents



three-to-five mark-to-market
 Pro Forma
    Quantitative and Qualitative Disclosure About Market
    Risk      Commodity
    Price Risk
      Swaps.
 111




---



##### Table of Contents



Put Options.
  Collars.
  Interest
    Rate Risk
    Counterparty
    and Customer Credit Risk
     Predecessor
    Results of Operations    Factors
    Affecting the Comparability of the Historical Financial Results
    of Our Predecessor.
    
    The following significant acquisitions by our predecessor:  
    The Forest Oil asset acquisition in June 2010 for approximately
    $65.9 million. 112




---



##### Table of Contents




    Two separate acquisitions of assets in East Texas in January and
    March 2010, respectively, for a net purchase price of
    approximately $14 million.
    Two separate acquisitions of assets in South Texas in April and
    May 2010, respectively, for a total purchase price of
    approximately $23.2 million.  
    The sale of certain non-core oil and natural gas properties
    located in South Texas in 2009 and 2008 for $11.8 million
    and $15.4 million, respectively.  period-to-period
  Three
    Months Ended March 31, 2010 Compared to the Three Months
    Ended March 31, 2011
    Three Months Ended March 31,2010


2011Revenues (in thousands):Oil and natural gas sales

$
7,879


$
11,641Other income


67



103Total revenues


7,946



11,744Costs and expenses (in thousands):Lease operating


2,220



5,170Exploration






Production and ad valorem taxes


509



693Depreciation, depletion and amortization


4,352



4,450Impairment of proved oil and natural gas properties


1,691



General and administrative


1,108



1,474Accretion


64



210(Gain) loss on derivative instruments


(6,636
)


703Gain on sale of properties






(8
)Other, net






Total costs and expenses


3,308



12,692Operating income (loss)


4,638



(948
)Interest expense


(606
)


(1,035
)Net income (loss)

$
4,032


$
(1,983
)Production:Oil (MBbls)


10



16NGLs (MBbls)


8



5Natural gas (MMcf)


1,224



2,266Total (MMcfe)


1,330



2,395Average net production (MMcfe/d)


14.8



26.6 113




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##### Table of Contents



Three Months Ended March 31,2010


2011Average sales price:Oil (per Bbl)

$
74.33


$
91.28NGLs (per Bbl)

$
44.30


$
52.09Natural gas (per Mcf)

$
5.55


$
4.36Total (per Mcfe)

$
5.92


$
4.86Average unit costs per Mcfe:Lease operating expenses

$
1.67


$
2.16Production and ad valorem taxes

$
0.38


$
0.29Depreciation, depletion and amortization

$
3.27


$
1.86Impairment of proved oil and natural gas properties

$
1.27


$
General and administrative expenses

$
0.83


$
0.62     Revenues.
  Lease Operating.
  Production and Ad Valorem
    Taxes.
  Depreciation, Depletion and
    Amortization.
  Impairment of Proved Oil and Natural Gas
    Properties.
  General and Administrative. period-over-period
 114




---



##### Table of Contents



(Gain) Loss on Derivative
    Instruments.
  Interest Expense.
 115




---



##### Table of Contents



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


2010Revenues (in thousands):Oil and natural gas sales

$
24,541


$
37,308Other income


319



1,433Total revenues


24,860



38,741Costs and expenses (in thousands):Lease operating


11,207



13,974Exploration


2,690



39Production and ad valorem taxes


1,464



2,112Depreciation, depletion and amortization


15,226



20,066Impairment of proved oil and natural gas properties


3,480



11,800General and administrative


4,811



6,116Accretion


320



663(Gain) loss on derivative instruments


(10,834
)


(10,264
)Gain on sale of properties


(7,851
)


(1
)Other, net


304



890Total costs and expenses


20,817



45,395Operating income (loss)


4,043



(6,654
)Interest expense


(2,937
)


(4,438
)Income (loss) before taxes


1,106



(11,092
)Income tax expense






(225
)Net income (loss)

$
1,106


$
(11,317
)Production:Oil (MBbls)


61



45NGLs (MBbls)


33



34Natural gas (MMcf)


5,282



7,314Total (MMcfe)


5,847



7,792Average net production (MMcfe/d)


16



21Average sales price:Oil (per Bbl)

$
58.01


$
75.81NGLs (per Bbl)

$
27.61


$
41.02Natural gas (per Mcf)

$
3.80


$
4.44Total (per Mcfe)

$
4.20


$
4.79Average unit cost per Mcfe:Lease operating expenses

$
1.92


$
1.79Production and ad valorem taxes

$
0.25


$
0.27Depreciation, depletion and amortization

$
2.60


$
2.58Impairment of proved oil and natural gas properties

$
0.60


$
1.51General and administrative expenses

$
0.82


$
0.78    116




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##### Table of Contents



Revenues.
  Lease Operating.
  Exploration.
  Production and Ad Valorem
    Taxes.
  Depreciation, Depletion and
    Amortization.
  Impairment of Proved Oil and Natural Gas
    Properties.
  General and Administrative.
  Gain on Derivative Instruments.
  Gain on Sale of Properties.
  Interest Expense.
 117




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##### Table of Contents



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


2009Revenues (in thousands):Oil and natural gas sales

$
49,313


$
24,541Other income


622



319Total revenues


49,935



24,860Costs and expenses (in thousands):Lease operating


8,843



11,207Exploration


374



2,690Production and ad valorem taxes


3,127



1,464Depreciation, depletion and amortization


12,353



15,226Impairment of proved oil and natural gas properties


14,166



3,480General and administrative


3,835



4,811Accretion


224



320(Gain) loss on derivative instruments


(9,815
)


(10,834
)Gain on sale of properties


(7,395
)


(7,851
)Other, net






304Total costs and expenses


25,712



20,817Operating income (loss)


24,223



4,043Interest expense


(3,138
)


(2,937
)Income tax expense






Net income (loss)

$
21,085


$
1,106Production:Oil (MBbls)


59



61NGLs (MBbls)


83



33Natural gas (MMcf)


4,719



5,282Total (MMcfe)


5,569



5,847Average net production (MMcfe/d)


15



16Average sales price:Oil (per Bbl)

$
100.58


$
58.01NGLs (per Bbl)

$
18.76


$
27.61Natural gas (per Mcf)

$
8.87


$
3.80Total (per Mcfe)

$
8.86


$
4.20Average unit costs per Mcfe:Lease operating expenses

$
1.59


$
1.92Production and ad valorem taxes

$
0.56


$
0.25Depreciation, depletion and amortization

$
2.22


$
2.60Impairment of proved oil and natural gas properties

$
2.54


$
0.60General and administrative expenses

$
0.69


$
0.82   year-over-year
  Revenues.
 118




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##### Table of Contents



Lease Operating.
  Exploration.
  Production and Ad Valorem
    Taxes.
  Depreciation, Depletion and
    Amortization.
  Impairment of Proved Oil and Natural Gas
    Properties.
  General and Administrative.
  Gain on Derivative Instruments.
  Interest Expense.
 Predecessor
    Liquidity and Capital Resources    Predecessor
    Cash Flows
    119




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##### Table of Contents



Year Ended December 31,

Three Months Ended March 31,2008

2009

2010

2010

2011Net cash provided by operating activities

$
32,838


$
12,672


$
20,288


$
3,935


$
2,999Net cash used in investing activities


(45,547
)


(24,947
)


(116,687
)


(10,601
)


(7,898
)Net cash provided by financing activities


11,619



15,989



96,756



9,434



1,375Net (decrease) increase in cash


(1,090
)


3,714



357



2,768



(3,524
)   Operating Activities.
  Investing Activities.
          Financing Activities.
  Predecessor
    Working Capital
   120




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##### Table of Contents



Predecessor
    Commodity Derivative Contracts
    Natural Gas SwapsWeighted AverageYear

($/MMBtu)

MMBtu/d2011

$
5.698



3,6332012

$
5.794



3,0492013

$
5.767



2,005   Natural Gas CollarsWeighted Average Floor

Weighted Average CeilingYear

($/MMBtu)

($/MMBtu)

MMBtu/d2011

$
5.305


$
6.761



6,5422012

$
4.897


$
6.177



9,0162013

$
4.778


$
5.790



11,474   Natural Gas Put OptionsYear

Floor Price ($/MMBtu)

MMBtu/d2011

$
4.300



8,2192012

$
4.800



2,295   Oil CollarsWeighted Average Floor

Weighted Average CeilingYear

($/MMBtu)

($/MMBtu)

Bbl/d2011

$
75.00


$
94.00



392012

$
73.33


$
94.97



302013

$
72.00


$
103.68



25   Predecessor
    Credit Facilities
    BlueStone. pre-payments
   121




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##### Table of Contents



Classic.
        Predecessor
    Contractual Obligations
    Payments Due by PeriodLess Than








More ThanContractual Obligation

Total


One Year


2-3 Years


4-5 Years


5 YearsRevolving credit facility

$
115,222


$



$



$
115,222


$
Operating lease


938



297



418



223



Capital lease


59



29



30







Other borrowings


222







138



84



Interest expense on long-term debt


12,364



2,718



4,823



4,823



Total contractual obligations

$
128,805


$
3,044


$
5,409


$
120,352


$
    Predecessor
    Quantitative and Qualitative Disclosure About Market
    Risk     122




---



##### Table of Contents



Commodity
    Price Risk
      Swaps.
    Put Options.
  Collars.
    Interest
    Rate Risk
   123




---



##### Table of Contents



Counterparty
    and Customer Credit Risk
     Critical
    Accounting Policies and Estimates  Oil
    and Natural Gas Properties
    units-of-production
   124




---



##### Table of Contents



Oil
    and Natural Gas Reserves
  12-month
  units-of-production
  Modernization of Oil and Gas Reporting
    Requirements
  12-month
  Impairments
   125




---



##### Table of Contents



property-by-property
  Asset
    Retirement Obligations
    Revenue
    Recognition
    Derivative
    Instruments
     Recently
    Issued Accounting Pronouncements  2010-20 2010-20 2010-20
  2010-14, Regulation S-X, Rule 4-10 Rule 33-8995. 2010-03 2010-14
 126




---



##### Table of Contents



2010-06, 2010-06 2010-06
 Internal
    Controls and Procedures             127




---



##### Table of Contents



Inflation   Off-Balance
    Sheet Arrangements   128




---



##### Table of Contents



BUSINESS
    AND PROPERTIES  The following Business and Properties discussion should be
    read in conjunction with the Selected Historical and Pro
    Forma Financial Data and the accompanying financial
    statements and related notes included elsewhere in this
    prospectus. Unless otherwise indicated, all references to
    financial or operating data on a pro forma basis give effect to
    the transactions described under Summary  Our
    Partnership Structure and Formation Transactions and in
    the Unaudited Pro Forma Combined Financial Statements included
    elsewhere in this prospectus.
  Our pro forma estimated proved reserve information for all of
    the Partnership Properties as of December 31, 2010 is based
    on the following: (1) approximately 53% of the estimated
    proved reserve volumes are based on a reserve report relating to
    our South Texas properties prepared by the independent petroleum
    engineers of NSAI; (2) approximately 35% of the estimated
    proved reserve volumes are based on evaluations relating to
    certain of our East Texas properties prepared by Memorial
    Resources internal reserve engineers and audited by NSAI;
    and (3) the remaining approximately 12% of the estimated
    proved reserve volumes are based on a reserve report relating to
    certain of our East Texas properties prepared by the independent
    petroleum engineers of Miller and Lents. We refer to these
    evaluations and reports collectively as our reserve
    reports.
 Overview  reserve-to-production
   Our
    Properties   129




---



##### Table of Contents



Estimated Pro Forma


Average Net


AverageNet Proved Reserves


Pro Forma


Reserve-to-


Producing% Natural


% Proved


Production


Production


WellsBcfe


Gas


Developed


MMcfe/d


%


Ratio(1)


Gross


Net(Years)South Texas


172.2



98
%


87
%


32



61
%


15



563



424East Texas


152.5



76
%


76
%


20



39
%


21



727



185Total


324.7



88
%


81
%


52



100
%


17



1,290



609     (1)
    
    The average
    reserve-to-production
    ratio is calculated by dividing estimated pro forma net proved
    reserves as of December 31, 2010 by average pro forma net
    production for the year ended December 31, 2010. Our
    Hedging Strategy  three-to-five
  and/or non-speculative
 Our
    Principal Business Relationships   130




---



##### Table of Contents



Our
    Relationship with Memorial Resource
      Estimated Pro Forma


Average Net


AverageNet Proved Reserves(1)


Pro Forma


Reserve-to-% Natural


% Proved


Production


Production


Producing WellsBcfe


Gas


Developed


MMcfe/d


%


Ratio(2)


Gross


Net(Years)East Texas(3)


760.6



84
%


30
%


43



64
%


48



1,067



306North Louisiana


224.7



73
%


44
%


18



27
%


35



267



172Rockies


51.0



67
%


41
%


6



9
%


25



123



85Total


1,036.3



81
%


34
%


67



100
%


43



1,457



563     (1)
    
    Memorial Resources estimated pro forma net proved reserves
    are based primarily on reserve reports prepared by third-party
    independent petroleum engineers.(2)
    
    The average
    reserve-to-production
    ratio is calculated by dividing estimated pro forma net proved
    reserves as of December 31, 2010 by average pro forma net
    production for the year ended December 31, 2010.(3)
    
    Includes 169 Bcfe of reserves associated with properties in
    which we have a joint ownership interest. Please read
    Summary  Our Partnership Structure and
    Formation Transactions  Background Information
    Regarding Our Predecessor and the Partnership Properties.   131




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##### Table of Contents



Our
    Relationship with NGP and the Funds
     Our
    Business Strategies    
    Maintain and Grow a Stable Production Profile through
    Accretive Acquisitions and Low-Risk
    Development.  Our development plans will
    target proved drilling locations that are low cost, present
    minimal risk, and support a stable production profile. We will
    seek to acquire proved developed properties with long-lived
    reserves, low production decline rates and identified and
    predictable development potential. We believe that our
    management teams experience positions us to identify,
    evaluate, execute, integrate and exploit suitable acquisitions.
    Strategically Utilize Our Relationship with Memorial
    Resource, the Funds, and their Respective Affiliates (Including
    NGP) to Gain Access to and, from Time to Time, Acquire Producing
    Oil and Natural Gas Properties that Meet Our Acquisition
    Criteria.  We may have the opportunity to
    acquire producing oil and natural gas properties directly from
    Memorial Resource, the Funds, or their respective affiliates
    from time to time in the future. While none of Memorial
    Resource, the Funds, or any of their respective affiliates is
    contractually obligated to offer or sell any properties to us,
    we 132




---



##### Table of Contents



believe that selling properties to us will enhance Memorial
    Resources and, accordingly, the Funds economic
    returns by monetizing long-lived producing properties while
    potentially retaining a portion of the resulting cash flow
    through distributions on Memorial Resources (and the
    Funds) limited partner and incentive distribution
    interests in us.  
    Leverage Our Relationships with Memorial Resource, the
    Funds, and their Respective Affiliates (Including NGP) to
    Participate in Acquisitions of Third Party Producing Properties
    and to Increase the Size and Scope of Our Potential Third-Party
    Acquisition Targets.  Memorial Resource was
    formed in part to acquire and develop oil and natural gas
    properties, some of which will likely meet our acquisition
    criteria. In addition, NGP and its affiliates (including the
    Funds) have long histories of pursuing and consummating oil and
    natural gas property acquisitions in North America. Through our
    relationships with Memorial Resource, the Funds, and their
    respective affiliates (including NGP), we expect that we will
    have access to their significant pool of management talent and
    industry relationships, which we believe will provide us a
    competitive advantage in pursuing potential third-party
    acquisition opportunities. We may have the opportunity to work
    jointly with Memorial Resource to pursue certain acquisitions of
    oil and natural gas properties that may not otherwise be
    attractive acquisition candidates for any of us individually.
    For example, we may jointly pursue an acquisition where we would
    acquire the proved developed portion of the acquired properties
    and Memorial Resource would acquire the undeveloped portion. We
    believe this arrangement will give us access to an array of
    third-party acquisition opportunities that we would not
    otherwise be in a position to pursue.
    Exploit Opportunities on Our Current Properties and Manage
    Our Operating Costs and Capital
    Expenditures.  We intend to pursue low-risk
    drilling of our proved undeveloped inventory and to perform
    cost-reducing operational enhancements. Pursuant to the omnibus
    agreement, Memorial Resource will provide us and our general
    partner with operating, management, and administrative services,
    which we believe will provide us with significant technical
    expertise and experience that will allow us to identify and
    execute cost-reducing exploitation and operational improvements
    on both our existing properties and new acquisitions. Memorial
    Resources operational control of substantially all of our
    proved reserves as well as its own, often adjoining or
    complementary properties, enables direct influence and
    implementation of cost reduction initiatives.
    Reduce Exposure to Commodity Price Risk and Stabilize Cash
    Flows Through a Disciplined Commodity Hedging
    Policy.  We intend to maintain a portfolio of
    commodity derivative contracts covering approximately 65% to 85%
    of our estimated production from total proved developed
    producing reserves over a
    three-to-five
    year period at any given point in time. These commodity
    derivative contracts may consist of natural gas, oil and NGL
    financial swaps and collar contracts and natural gas basis
    financial swaps. Memorial Resource will contribute to us at the
    closing of this offering derivative contracts for the six months
    ending December 31, 2011 and the years ending
    December 31, 2012, 2013, 2014, and 2015 covering
    approximately 76%, 75%, 69%, 14% and 8%, respectively, of our
    estimated production from our total proved developed producing
    reserves existing as of December 31, 2010, based on our
    reserve reports. We believe these commodity derivative contracts
    will allow us to mitigate the impact of oil and natural gas
    price volatility, thereby increasing the predictability of our
    cash flow.
    Maintain Reasonable Levels of Indebtedness to Permit us to
    Opportunistically Finance Acquisitions.  We
    intend to maintain modest levels of indebtedness in relation to
    our cash flows from operations. We believe our internally
    generated cash flows and our borrowing capacity under our new
    revolving credit facility will provide us with the financial
    flexibility to pursue our acquisition and development strategy
    in an effective and competitive manner. 133




---



##### Table of Contents



Our
    Competitive Strengths    
    Our Long-Lived Reserves with Significant Production
    History and Predictable Production Decline
    Rates.  Our pro forma estimated proved
    reserves as of December 31, 2010 divided by our pro forma
    average net production for 2010, which we refer to as our
    reserve to production index, was 17 years. Based on our
    reserve reports, the average estimated decline rate for our
    existing proved developed producing reserves is approximately 9%
    for 2011, approximately 9% compounded average decline for the
    subsequent four years and approximately 8% thereafter. Our
    estimated average well life for producing reserves is
    12 years, providing a long history of production that
    enables better predictability of future production decline rates.
    Our Relationships with Memorial Resource, the Funds, and
    their Respective Affiliates (Including NGP), which we Believe
    will Provide us with Access to a Portfolio of Additional Oil and
    Natural Gas Properties that Meet Our Acquisition
    Criteria.  Memorial Resource was formed in
    part to own and acquire producing properties and to develop
    properties into mature, long-lived producing assets. After
    giving effect to the formation transactions, Memorial Resource
    had (i) total estimated proved reserves of 1,036 Bcfe
    at December 31, 2010, primarily located in East Texas,
    North Louisiana and the Rockies, of which approximately 81% were
    natural gas, and approximately 34% were classified as proved
    developed reserves, and (ii) interests in over
    398,000 gross (173,000 net) acres of undeveloped
    properties. Based on Memorial Resources intention to
    develop its properties and Memorial Resources significant
    ownership interests in us, we believe we may be able to acquire
    additional assets from Memorial Resource, the Funds, or their
    respective affiliates in the future. None of Memorial Resource,
    the Funds, or any of their respective affiliates will have any
    obligation to offer or sell properties to us following the
    consummation of this offering.
    Our Management Teams Extensive Experience in the
    Acquisition, Development and Integration of Oil and Natural Gas
    Assets.  The members of our management team
    and Memorial Resource collectively have an average of
    24 years of experience in the oil and natural gas industry.
    John A. Weinzierl, the President, Chief Executive Officer and
    Chairman of our general partner, has 20 years of oil and
    natural gas industry experience, a strong commercial and
    technical background and extensive experience acquiring and
    managing oil and natural gas properties for NGP.
    Our Relationship with Memorial Resource, which Provides us
    with Extensive Technical Expertise in and Familiarity with
    Developing and Operating Oil and Natural Gas Assets within Our
    Core Focus Areas.  Through the omnibus
    agreement with Memorial Resource, we have the operational
    support of a staff of 50 petroleum professionals, many of whom
    have significant engineering and geoscience expertise in South
    and/or East
    Texas, which are our current geographical areas of focus. We
    believe that this technical expertise differentiates us from,
    and provides us with a competitive advantage over, many of our
    competitors. We intend to utilize these resources in maximizing
    our production and ultimate reserve recovery, which could add
    substantial value to our assets.
    Our Relationships with Memorial Resource, the Funds, and
    their Respective Affiliates (Including NGP), which we Believe
    will Help us with Access to and in the Evaluation and Execution
    of Future Acquisitions.  We believe that our
    ability to use the industry relationships and broad expertise of
    Memorial Resource and NGP in expanding our access to
    acquisitions and evaluating oil and natural gas assets will
    expand our opportunities and differentiate us from many of our
    competitors. Additionally, we expect to have the opportunity to
    work jointly with Memorial Resource to pursue acquisitions of
    oil and natural gas properties that we would not otherwise be
    able to pursue on our own or that may not otherwise be
    attractive acquisition candidates for any of us individually.
    Our Diverse Distribution of Reserve Value, with
    1,290 Gross (609 Net) Producing Wells as of
    December 31, 2010, None of which Contains Estimated Proved
    Reserves in Excess of 2% of Our Total Estimated Proved Reserves
    as of December 31, 2010.  The value of
    our pro forma estimated 134




---



##### Table of Contents



proved reserves, as approximated by the standardized measure, is
    spread across a wide subset of our producing wells. Our top
    10 wells by value represent 11% of our total standardized
    measure at December 31, 2010. The value of our pro forma
    estimated proved reserves, as approximated by the standardized
    measure, is also widely distributed across our producing fields.
    No producing field in our pro forma estimated proved reserves
    represents more than 36% of our standardized measure at
    December 31, 2010.  
    Our Inventory of 345 Proved Low-Risk Infill Drilling,
    Recompletion and Development Opportunities in Our Core
    Operational Areas.  We have a substantial
    inventory of low risk, proved undeveloped locations. At
    December 31, 2010, the Partnership Properties included
    60 Bcfe of estimated proved undeveloped reserves, and had
    70 proved identified low-risk proved drilling locations and
    275 proved recompletion and development opportunities.
    Based on our current asset portfolio, we intend to spend
    approximately $9.2 million for capital expenditures for the
    twelve months ending June 30, 2012 based on our reserve
    reports, which amount spent annually we believe will also enable
    us to maintain our targeted average net production from our
    assets of 49 MMcfe/d through December 31, 2015.
    Our Competitive Cost of Capital and Financial
    Flexibility.  Unlike our corporate
    competitors, we do not expect to be subject to federal income
    taxation at the entity level. We believe that this attribute
    should provide us with a lower cost of capital compared to many
    of our competitors, thereby enhancing our ability to compete for
    future acquisitions, both individually and jointly with Memorial
    Resource. We also expect that our ability to issue additional
    common units and other partnership interests in connection with
    acquisitions will enhance our financial flexibility. Further, we
    intend to utilize a modest amount of debt to provide flexibility
    in our capital structure. Properties       135




---



##### Table of Contents



Pro Forma Average Net Production for theYear Ended December 31, 2010


AverageEstimated Net Proved Reserves





% of


Reserve-to-% Proved


% Natural


% of





Total


ProductionMMcfe


Developed


Gas


Total


(MMcfe/d)


Production


RatioSouth Texas Fields:NE Thompsonville


32,312



85
%


100
%


19
%


7



23
%


12Laredo


23,993



63
%


98
%


14
%


5



17
%


12Hubberd


19,166



100
%


98
%


11
%


3



9
%


18East Seven Sisters


17,820



100
%


100
%


10
%


4



12
%


13Other


78,871



88
%


97
%


46
%


12



39
%


18Total South Texas Fields


172,161



87
%


98
%


100
%


32



100
%


15East Texas Fields:Carthage


117,721



73
%


72
%


77
%


12



57
%


28Joaquin


18,519



100
%


99
%


12
%


7



35
%


7Other


16,296



100
%


81
%


11
%


2



8
%


26Total East Texas Fields


152,536



76
%


76
%


100
%


20



100
%


21All Fields


324,697



81
%


88
%


100
%


52



100
%


17   Summary
    of Oil and Natural Gas Properties and Projects
  reserve-to-production reserve-to-production
  South Texas.
 136




---



##### Table of Contents



NE Thompsonville Field.
  Laredo Field.
  Hubberd Field.
  East Seven Sisters Field.
  East Texas.
  Joaquin Field.
  Carthage Field.
 137




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##### Table of Contents



Oil and
    Natural Gas Data and Operations  Properties  Internal
    Controls
    and/or
    
    A reserve audit is an examination of reserve information that is
    conducted for the purpose of expressing an opinion as to whether
    such reserve information, in the aggregate, is reasonable and
    has been presented in conformity with generally accepted
    petroleum engineering and evaluation principles.
    The estimation of proved reserves is an imprecise science due to
    the many unknown geologic and reservoir factors that cannot be
    estimated through sampling techniques. Since reserves are only
    estimates, they cannot be audited for the purpose of verifying
    exactness. Instead, reserve information is audited for the
    purpose of reviewing in sufficient detail the policies,
    procedures and methods used by a company in estimating its
    reserves so that the reserve auditors may express an opinion as
    to whether, in the aggregate, the reserve information furnished
    by a company is reasonable.
    The methods and procedures used by a company, and the reserve
    information furnished by a company, must be reviewed in
    sufficient detail to permit the reserve auditor, in its
    professional judgment, to express an opinion as to the
    reasonableness of the reserve information. The auditing
    procedures require the reserve auditor to prepare its own
    estimates of reserve information for the audited properties.   138




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Technology
    Used to Establish Proved Reserves
      Qualifications
    of Responsible Technical Persons
  Netherland, Sewell & Associates,
    Inc.
           139




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Miller and Lents, Ltd.
    Estimated
    Proved Reserves
    PartnershipProperties as ofDecember 31, 2010Estimated Proved ReservesOil (MBbls)


2,002NGLs (MBbls)


4,502Natural gas (MMcf)


285,676Total (MMcfe)(1)


324,697Proved developed (MMcfe)


264,572Proved undeveloped (MMcfe)


60,125Proved developed reserves as a percentage of total proved
    reserves


81
%Standardized measure (in millions)(2)(3)

$
359.2Oil and Natural Gas Prices(4)Oil  WTI Posting (Plains) per Bbl

$
75.96Natural gas  NYMEX-Henry Hub per MMBtu

$
4.38     (1)
    
    Determined using a ratio of six Mcf of natural gas to one Bbl of
    oil, condensate or NGLs based on an approximate energy
    equivalency. This is an energy content correlation and does not
    reflect a value or price relationship between the commodities.(2)
    
    Standardized measure is the present value of estimated future
    net revenues to be generated from the production of proved
    reserves, determined in accordance with the rules and
    regulations of the SEC without giving effect to non-property
    related expenses, such as general and administrative expenses,
    interest and income tax expenses, or to depreciation, depletion
    and amortization. The future cash flows are discounted using an
    annual discount rate of 10%. Because we are a limited
    partnership, we are generally not subject to federal income
    taxes and thus make no provision for federal income taxes in the
    calculation of our standardized measure. Standardized measure
    does not give effect to derivative transactions. We expect to
    hedge a substantial portion of our future estimated production
    from total proved producing reserves. For a description of our
    expected commodity derivative contracts, please read
    Managements Discussion and 140




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Analysis of Financial Condition and Results of
    Operations  Pro Forma Liquidity and Capital
    Resources  Commodity Derivative Contracts.(3)
    
    Because we are subject to Texas margin tax, standardized measure
    was negatively impacted by $5.0 million.(4)
    
    Our estimated net proved reserves and related standardized
    measure were determined using index prices for oil and natural
    gas, without giving effect to derivative contracts, held
    constant throughout the life of the properties. These prices
    were adjusted by lease for quality, transportation fees,
    geographical differentials, marketing bonuses or deductions and
    other factors affecting the price received at the wellhead.      Development
    of Proved Undeveloped Reserves
     141




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Production,
    Revenues and Price History
    Memorial Production Partners LPOur Predecessor

Pro FormaYear Ended

Three MonthsYear Ended December 31,

December 31,

Ended March 31,2008

2009

2010

2010

2011Production and operating data:Net production volumes:Oil (MBbls)


59



61



45



107



28NGLs (MBbls)


83



33



34



272



56Natural gas (MMcf)


4,719



5,282



7,314



16,713



3,897Total (MMcfe)


5,569



5,847



7,792



18,985



4,399Average net production (MMcfe/d)


15



16



21



52



49Average sales price:(1)Oil (per Bbl)

$
100.58


$
58.01


$
75.81


$
74.35


$
90.11NGLs (per Bbl)

$
18.76


$
27.61


$
41.02


$
37.41


$
43.76Natural gas (per Mcf)

$
8.87


$
3.80


$
4.44


$
4.17


$
4.02Average price per Mcfe

$
8.86


$
4.20


$
4.79


$
4.62


$
4.69Average unit costs per Mcfe:Lease operating expenses

$
1.59


$
1.92


$
1.79


$
1.21


$
1.52Production taxes and ad valorem taxes

$
0.56


$
0.25


$
0.27


$
0.39


$
0.39General and administrative expenses

$
0.69


$
0.82


$
0.78


$
0.31


$
0.32Depreciation, depletion and amortization

$
2.22


$
2.60


$
2.58


$
1.83


$
1.60     (1)
    
    Prices do not include the effects of derivative cash settlements.  Present
    Drilling and Other Exploratory and Development
    Activities
  Drilling Activities.
  Other Exploratory and Development
    Activities.
  Predecessor
    Drilling and Other Exploratory and Development
    Activities
    Productive
    Wells
   142




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Oil


Natural GasGross


Net


Gross


NetOperated


4



3



542



422Non-operated










36



2Total


4



3



578



424   Developed
    Acreage
    Developed Acreage(1)Gross(2)


Net(3)South Texas


82,400



72,744East Texas






Total


82,400



72,744     (1)
    
    Developed acres are acres spaced or assigned to productive wells
    or wells capable of production.(2)
    
    A gross acre is an acre in which we own a working interest. The
    number of gross acres is the total number of acres in which we
    own a working interest.(3)
    
    A net acre is deemed to exist when the sum of the fractional
    ownership working interests in gross acres equals one. The
    number of net acres is the sum of the fractional working
    interests owned in gross acres expressed as whole numbers and
    fractions thereof.  Delivery
    Commitments
   Oil and
    Natural Gas Data and Operations  Our
    Predecessor  Drilling
    Activities
   143




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Year Ended December 31,2008


2009


2010Gross


Net


Gross


Net


Gross


NetDevelopment wells:Productive


17.0



13.5



4.0



3.7



3.0



2.7Dry


4.0



2.5



1.0



0.9







Exploratory wells:Productive






















Dry






















Total wells:Productive


17.0



13.5



4.0



3.7



3.0



2.7Dry


4.0



2.5



1.0



0.9







Total


21.0



16.0



5.0



4.6



3.0



2.7  Operations  General
  and/or
  Oil
    and Natural Gas Leases
    Marketing
    and Major Customers
  month-to-month
  month-to-month 30-day
 144




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Competition
        Title
    to Properties
    rights-of-way
 145




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Seasonal
    Nature of Business
   Environmental
    Matters and Regulation  General
          Hazardous
    Substances and Waste
   146




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Water
    Discharges
     147




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Air
    Emissions
    Climate
    Change
  2
 148




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cap-and-trade and/or
    National
    Environmental Policy Act
   149




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Endangered
    Species Act
    OSHA
  and/or
 Other
    Regulation of the Oil and Natural Gas Industry      Drilling
    and Production
    
    the location of wells;
    the method of drilling and casing wells;
    the surface use and restoration of properties upon which wells
    are drilled;
    the plugging and abandoning of wells; and
    notice to surface owners and other third parties. 150




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Natural
    Gas Regulation
      State Regulation.
   Employees     151




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Offices   Legal
    Proceedings   152




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MANAGEMENT Management
    of Memorial Production Partners LP           153




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Board
    Leadership Structure and Role in Risk Oversight
     154




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##### Table of Contents



Directors
    and Executive Officers    Name

Age

Position with Our General PartnerJohn A. Weinzierl


43


President, Chief Executive Officer, and ChairmanAndrew J. Cozby


44


Vice President, FinancePatrick T. Nguyen


38


Chief Accounting OfficerGregory M. Robbins


32


TreasurerKenneth A. Hersh


48


Director     John A. Weinzierl
    Andrew J. Cozby
  Patrick T. Nguyen
  Gregory M. Robbins
 155




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Kenneth A. Hersh
   Reimbursement
    of Expenses of Our General Partner     Executive
    Compensation   156




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day-to-day
    Compensation
    Committee Interlocks and Insider Participation
   Compensation
    Discussion and Analysis  General
       157




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pay-for-performance pay-for-performance
         158




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Awards
    Under Our Long-Term Incentive Plan
   Director
    Compensation    out-of-pocket
 Long-Term
    Incentive Plan       159




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Restricted
    Units
      Phantom
    Units
      Unit
    Options
    Unit
    Appreciation Rights
    Distribution
    Equivalent Rights
   160




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Other
    Unit-Based Awards
    Unit
    Awards
    Change
    in Control; Termination of Service
  and/or
  Source
    of Common Units
   Relation
    of Compensation Policies and Practices to Risk
    Management         161




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SECURITY
    OWNERSHIP OF CERTAIN
    BENEFICIAL OWNERS AND MANAGEMENT    
    each person who then will beneficially own more than 5% of the
    then outstanding common units;
    each director and director nominee of our general partner;
    each named executive officer of our general partner; and
    all directors, director nominees and named executive officers of
    our general partner as a group.  Percentage ofTotalPercentage of



Percentage of

Common andCommon

Common

Subordinated

Subordinated

SubordinatedUnits to be

Units to be

Units to be

Units to be

Units to beBeneficially

Beneficially

Beneficially

Beneficially

BeneficiallyName of Beneficial Owner(1)

Owned(2)

Owned

Owned

Owned

OwnedMemorial Resource(3)







%







%



%Kenneth A. Hersh(4)







%







%



%All named executive officers, directors and director nominees as
    a group (five persons)







%







%



%     (1)
    
    The address for all beneficial owners in this table is 1401
    McKinney Street, Suite 1025, Houston, Texas 77010. There
    are no options, warrants or other rights or obligations
    outstanding that are currently exercisable or exercisable within
    60 days into common or subordinated units.(2)
    
    Does not include any common units that may be purchased in a
    directed unit program.(3)
    
    Memorial Resource is owned by Natural Gas Partners VIII, L.P.
    (NGP VIII) and Natural Gas Partners IX, L.P.
    (NGP IX), which also collectively directly own,
    through non-voting membership interests in our general partner,
    50% of the economic interest in our incentive distribution
    rights. NGP VIII and NGP IX may be deemed to share voting and
    dispositive power over the reported securities; thus, each may
    also be deemed to be the beneficial owner of these securities.
    Each of NGP VIII and NGP IX disclaims beneficial ownership of
    the reported securities in excess of such entitys
    respective pecuniary interest in the securities.(4)
    
    G.F.W. Energy VIII, L.P., GFW VIII, L.L.C., G.F.W. Energy IX,
    L.P. and GFW IX, L.L.C. may be deemed to beneficially own the
    units held by Memorial Resource that are attributable to NGP
    VIII and NGP IX by virtue of GFW VIII, L.L.C. being the sole
    general partner of G.F.W. Energy VIII, L.P. (which is the
    general partner of NGP VIII) and GFW IX, L.L.C. being the
    sole general partner of G.F.W. Energy IX, L.P. (which is the
    general partner of NGP IX). Kenneth A. Hersh, one of our general
    partners directors and who is an Authorized Member of each
    of GFW VIII, L.L.C. and GFW IX, L.L.C., may also be deemed to
    share the power to vote, or to direct the vote, and to dispose,
    or to direct the disposition, of those units. Mr. Hersh
    does not own directly any common units or subordinated units.    Class A

Class BMember

MemberName of Beneficial Owner

Interest(a)

Interest(a)Memorial Resource(b)


100
%


Natural Gas Partners VIII, L.P.(c)(d)







%Natural Gas Partners IX, L.P.(c)(d)







%  162




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##### Table of Contents



(a)
    
    Our general partner has two classes of member interests.
    Memorial Resource owns the voting Class A member interest,
    and will be entitled to 50% of any cash distributions made or
    common units issued to our general partner with respect to our
    general partners 0.1% general partner interest in us. NGP
    VIII and NGP IX
    own     %     and
    %, respectively, of the non-voting Class B member interest
    in our general partner, which entitles them to an aggregate 50%
    of any cash distributions made or common units issued to our
    general partner.(b)
    
    Our general partner is controlled by Memorial Resource, which is
    controlled by NGP VIII and NGP IX. Mr. Hersh will share in
    distributions made by us with respect to interests held by our
    general partner in proportion to his pecuniary interests.
    Mr. Hersh disclaims beneficial ownership of the reported
    securities in excess of his pecuniary interest in such
    securities. In addition, our general partners other
    non-independent directors and certain of our general
    partners executive officers have indirect financial
    interests in Memorial Resource and its affiliates.(c)
    
    NGP VIII and NGP IX may be deemed to share voting and
    dispositive power over the reported interests of Memorial
    Resource; thus, each of NGP VIII and NGP IX may also be deemed
    to be the beneficial owner of these interests. Each of NGP VIII
    and NGP IX disclaims beneficial ownership of such reported
    interests in excess of such entitys respective pecuniary
    interest in such interests. G.F.W. Energy VIII, L.P., GFW VIII,
    L.L.C., G.F.W. Energy IX, L.P. and GFW IX, L.L.C. may be deemed
    to beneficially own the interests owned by Memorial Resource
    attributable to NGP VIII and NGP IX and the interests held by
    NGP VIII and NGP IX by virtue of GFW VIII, L.L.C. being the sole
    general partner of G.F.W. Energy VIII, L.P. (which is the
    general partner of NGP VIII) and GFW IX, L.L.C. being the
    sole general partner of G.F.W. Energy IX, L.P. (which is the
    general partner of NGP IX). Kenneth A. Hersh, one of our general
    partners directors and who is an Authorized Member of each
    of GFW VIII, L.L.C. and GFW IX, L.L.C., may also be deemed to
    share the power to vote, or to direct the vote, and to dispose,
    or to direct the disposition, of the interests held by NGP VII
    and NGP IX. Mr. Hersh does not own directly any interests
    in our general partner.(d)
    
    The address for NGP VIII and NGP IX is 125 E. John
    Carpenter Fwy., Suite 600, Irving, Texas 75602. 163




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CERTAIN
    RELATIONSHIPS AND RELATED PARTY TRANSACTIONS   Distributions
    and Payments to Our General Partner and Its Affiliates    Formation
    Stage
  The consideration received by our
    
               common
    units;general partner and Memorial Resource
    
               subordinated
    units;prior to or in connection with this offering
    
               general
    partner units
    (or          general
    partner units if the underwriters exercise their option to
    purchase additional common units in full); all of our incentive distribution rights; and approximately
    $      million in cash.  Operational
    Stage
  Distributions of available cash to our general partner and its
    affiliates
    
    We will generally make cash distributions 99.9% to our
    unitholders, including Memorial Resource as the holder of
    approximately     % of our limited
    partner interests, pro rata and 0.1% to our general partner,
    assuming it makes any capital contributions necessary to
    maintain its 0.1% general partner interest in us. In addition,
    if distributions exceed the minimum quarterly distribution and
    other higher target distribution levels, our general partner
    will be entitled to increasing percentages of the distributions,
    up to a maximum of 25.0% of the distributions above the highest
    target distribution level, including the general partners
    0.1% general partner interest.Assuming we have sufficient available cash to pay the full
    minimum quarterly distribution on all of our outstanding units
    for four quarters, our general partner would receive an annual
    distribution of approximately
    $      million on its general
    partner units and Memorial Resource would receive an annual
    distribution of approximately
    $      million on its common units
    and subordinated units.Payments to our general partner and its affiliates
    
    Our general partner will not receive a management fee or other
    compensation for its management of our partnership, but we will
    reimburse our general partner for all direct and indirect
    expenses it incurs or payments it makes on our behalf and all
    other expenses 164




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allocable to us or otherwise incurred by our general partner and
    its affiliates in connection with operating our business. Our
    partnership agreement does not set a limit on the amount of
    expenses for which our general partner may be reimbursed. These
    expenses include salary, bonus, incentive compensation and other
    amounts paid to persons who perform services for us or on our
    behalf and expenses allocated to our general partner by its
    affiliates. Our partnership agreement provides that our general
    partner will determine in good faith the amount of such expenses
    that are allocable to us.Withdrawal or removal of our general partner
    
    If our general partner is removed under circumstances where
    cause exists or withdraws where that withdrawal violates our
    partnership agreement, a successor general partner will have the
    option to purchase the departing general partners general
    partner interest in us and the incentive distribution rights for
    a cash payment equal to the fair market value of those
    interests. Under all other circumstances where our general
    partner withdraws or is removed by the limited partners, the
    departing general partner will have the option to require the
    successor general partner to purchase the departing general
    partners general partner interest in us and its incentive
    distribution rights for their fair market value or to convert
    such interests into common units.  Liquidation
    Stage
  Liquidation
    
    Upon our liquidation, the partners, including our general
    partner, will be entitled to receive liquidating distributions
    according to their respective capital account balances. Amended
    and Restated Limited Liability Company Agreement of Memorial
    Production Partners GP LLC     Agreements
    Governing the Transactions   165




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##### Table of Contents



Omnibus
    Agreement
    
    our obligation to reimburse Memorial Resource for all expenses
    incurred by Memorial Resource (or payments made on our behalf)
    in conjunction with its provision of general and administrative
    services to us, including, but not limited to, our public
    company expenses and an allocated portion of the salary and
    benefits of the executive officers of our general partner and
    other employees of Memorial Resource who perform services for us
    or on our behalf;
    our obligation to reimburse Memorial Resource for insurance
    coverage expenses it incurs with respect to our business and
    operations and with respect to director and officer liability
    coverage for the officers and directors of our general
    partner; and
    our obligation to indemnify Memorial Resource for certain
    liabilities.    Tax
    Sharing Agreement
    Purchase
    and Sale and Contribution Agreements
   Review,
    Approval or Ratification of Transactions with Related
    Persons   166




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167




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##### Table of Contents



CONFLICTS
    OF INTEREST AND FIDUCIARY DUTIES Conflicts
    of Interest        
    approved by the conflicts committee, although our general
    partner is not obligated to seek such approval;
    approved by the vote of a majority of the outstanding common
    units, excluding any common units owned by our general partner
    or any of its affiliates;
    on terms no less favorable to us than those generally being
    provided to or available from unrelated third parties; or
    fair and reasonable to us, taking into account the totality of
    the relationships among the parties involved, including other
    transactions that may be particularly favorable or advantageous
    to us.     168




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##### Table of Contents



Memorial
    Resource, the Funds and other affiliates of our general partner
    will not be limited in their ability to compete with us, which
    could cause conflicts of interest and limit our ability to
    acquire additional assets or businesses.
        Neither
    our partnership agreement nor any other agreement requires
    Memorial Resource, the Funds or NGP to pursue a business
    strategy that favors us. The directors and officers of Memorial
    Resource, the Funds and their respective affiliates (including
    NGP) have a fiduciary duty to make decisions in the best
    interests of their respective equity holders, which may be
    contrary to our interests.
  and/or
    Our
    general partner is allowed to take into account the interests of
    parties other than us in resolving conflicts of
    interest.
    Many
    of the directors and all of the officers who have responsibility
    for our management have significant duties with, and will spend
    significant time serving, entities that compete with us in
    seeking acquisitions
 169




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##### Table of Contents



and business opportunities and, accordingly, may have
    conflicts of interest in allocating time or pursuing business
    opportunities.
    Neither
    we nor our general partner have any employees and we will rely
    solely on the employees of Memorial Resource to manage our
    business. The management team of Memorial Resource, which
    includes the individuals who will manage us, will also perform
    substantially similar services for itself and will own and
    operate its own assets, and thus will not be solely focused on
    our business.
     170




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Our
    partnership agreement limits our general partners
    fiduciary duties to holders of our units and restricts the
    remedies available to unitholders for actions taken by our
    general partner that might otherwise constitute breaches of
    fiduciary duty.
    
    permits our general partner to make a number of decisions in its
    individual capacity, as opposed to in its capacity as our
    general partner. This entitles our general partner to consider
    only the interests and factors that it desires, and it has no
    duty or obligation to give any consideration to any interest of,
    or factors affecting, us, our affiliates or any limited partner.
    Examples include the exercise of its right to reset the target
    distribution levels of its incentive distribution rights at
    higher levels and receive, in connection with this reset, common
    units, the exercise of its limited call right, the exercise of
    its rights to transfer or vote the units it owns, the exercise
    of its registration rights and its determination whether or not
    to consent to any merger or consolidation involving us or to any
    amendment to the partnership agreement;
    provides that our general partner will not have any liability to
    us or our unitholders for decisions made in its capacity as
    general partner so long as it acted in good faith;
    generally provides that affiliated transactions and resolutions
    of conflicts of interest not approved by the conflicts committee
    of the board of directors of our general partner acting in good
    faith and not involving a vote of unitholders must be on terms
    no less favorable to us than those generally being provided to
    or available from unrelated third parties or must be fair
    and reasonable to us, as determined by our general partner
    in good faith. In determining whether a transaction or
    resolution is fair and reasonable, our general
    partner may consider the totality of the relationships between
    the parties involved, including other transactions that may be
    particularly advantageous or beneficial to us;
    provides that our general partner and its officers and directors
    will not be liable for monetary damages to us or our limited
    partners for any acts or omissions unless there has been a final
    and non-appealable judgment entered by a court of competent
    jurisdiction determining that our general partner or its
    officers and directors acted in bad faith or engaged in fraud or
    willful misconduct or, in the case of a criminal matter, acted
    with knowledge that the conduct was criminal; and
    provides that in resolving conflicts of interest, it will be
    presumed that in making its decision our general partners
    board of directors or the conflicts committee of our general
    partners board of directors acted in good faith, and in
    any proceeding brought by or on behalf of any limited partner or
    us, the person bringing or prosecuting such proceeding will have
    the burden of overcoming such presumption.    Except
    in limited circumstances, our general partner has the power and
    authority to conduct our business without unitholder
    approval.
    
    the making of any expenditures, the lending or borrowing of
    money, the assumption or guarantee of or other contracting for,
    indebtedness and other liabilities, the issuance of evidences of
    indebtedness, including indebtedness that is convertible into
    our securities, and the incurring of any other obligations;
    the purchase, sale or other acquisition or disposition of our
    securities, or the issuance of additional options, rights,
    warrants and unit appreciation rights relating to our securities; 171




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
    the mortgage, pledge, encumbrance, hypothecation or exchange of
    any or all of our assets;
    the negotiation, execution and performance of any contracts,
    conveyances or other instruments;
    the distribution of our cash;
    the selection and dismissal of employees and agents, outside
    attorneys, accountants, consultants and contractors and the
    determination of their compensation and other terms of
    employment or hiring;
    the maintenance of insurance for our benefit and the benefit of
    our partners;
    the formation of, or acquisition of an interest in, the
    contribution of property to, and the making of loans to, any
    limited or general partnerships, joint ventures, corporations,
    limited liability companies or other entities;
    the control of any matters affecting our rights and obligations,
    including the bringing and defending of actions at law or in
    equity and otherwise engaging in the conduct of litigation,
    arbitration or mediation and the incurring of legal expense and
    the settlement of claims and litigation;
    the indemnification of any person against liabilities and
    contingencies to the extent permitted by law;
    the making of tax, regulatory and other filings or rendering of
    periodic or other reports to governmental or other agencies
    having jurisdiction over our business or assets; and
    the entering into of agreements with any of its affiliates to
    render services to us or to itself in the discharge of its
    duties as our general partner.    Our
    general partner determines the amount and timing of asset
    purchases and sales, capital expenditures, borrowings, issuance
    of additional partnership interests and the creation, reduction
    or increase of reserves, each of which can affect the amount of
    cash that is distributed to our unitholders.
    
    the manner in which our business is operated;
    the amount, nature and timing of asset purchases and sales;
    the amount, nature and timing of our capital expenditures;
    the amount of borrowings;
    the issuance of additional units; and
    the creation, reduction or increase of reserves in any quarter.     172




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Our
    general partner determines which costs incurred by it are
    reimbursable by us.
    Our
    partnership agreement does not restrict our general partner from
    causing us to pay it or its affiliates for any services rendered
    to us or entering into additional contractual arrangements with
    any of these entities on our behalf.
        Our
    general partner may exercise its right to call and purchase
    common units if it and its affiliates own more than 80% of the
    common units.
    Common
    unitholders will have no right to enforce obligations of our
    general partner and its affiliates under agreements with
    us.
   173




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Our
    general partner and Memorial Resource may be able to amend our
    partnership agreement without the approval of any other
    unitholder after the subordination period.
    Our
    general partner intends to limit its liability regarding our
    obligations.
    Contracts
    between us, on the one hand, and our general partner and its
    affiliates, on the other, will not be the result of
    arms-length negotiations.
    Our
    general partner decides whether to retain separate counsel,
    accountants or others to perform services for us.
    Our
    general partner may elect to cause us to issue common units to
    it in connection with a resetting of the target distribution
    levels related to our general partners incentive
    distribution rights without the approval of the conflicts
    committee of the board of directors of our general partner or
    our unitholders. This election may result in lower distributions
    to our common unitholders in certain situations.
   174




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Fiduciary
    Duties     175




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State-law fiduciary duty standards
    
    Fiduciary duties are generally considered to include an
    obligation to act in good faith and with due care and loyalty.
    The duty of care, in the absence of a provision in a partnership
    agreement providing otherwise, would generally require a general
    partner to act for the partnership in the same manner as a
    prudent person would act on his own behalf. The duty of loyalty,
    in the absence of a provision in a partnership agreement
    providing otherwise, would generally prohibit a general partner
    of a Delaware limited partnership from taking any action or
    engaging in any transaction where a conflict of interest is
    present.Rights and remedies of unitholders
    
    The Delaware Act generally provides that a limited partner may
    institute legal action on behalf of the partnership to recover
    damages from a third-party where a general partner has refused
    to institute the action or where an effort to cause a general
    partner to do so is not likely to succeed. In addition, the
    statutory or case law of some jurisdictions may permit a limited
    partner to institute legal action on behalf of himself and all
    other similarly situated limited partners to recover damages
    from a general partner for violations of its fiduciary duties to
    the limited partners.Partnership agreement modified standards
    
    Our partnership agreement contains provisions that waive or
    consent to conduct by our general partner and its affiliates
    that might otherwise raise issues about compliance with
    fiduciary duties or applicable law. For example, our partnership
    agreement provides that when our general partner is acting in
    its capacity as our general partner, as opposed to in its
    individual capacity, it must act in good faith and
    will not be subject to any other standard under applicable law.
    In addition, when our general partner is acting in its
    individual capacity, as opposed to in its capacity as our
    general partner, it may act without any fiduciary obligation to
    us or the unitholders whatsoever. These standards reduce the
    obligations to which our general partner would otherwise be held.In addition to the other more specific provisions limiting the
    obligations of our general partner, our partnership agreement
    further provides that our general partner and its officers and
    directors will not be liable for monetary damages to us or our
    limited partners for errors of judgment or for any acts or
    omissions unless there has been a final and non-appealable
    judgment by a court of competent jurisdiction determining that
    our general partner or its officers and directors acted in bad
    faith or engaged in fraud or willful misconduct, or in the case
    of a criminal matter, acted with the knowledge that such conduct
    was unlawful. 176




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Special Provisions Regarding Affiliate
    Transactions.  Our partnership agreement
    generally provides that affiliate transactions and resolutions
    of conflicts of interest that are not approved by vote of
    unitholders and that are not approved by the conflicts committee
    of the board of directors of our general partner must be: on terms no less favorable to us than those
    generally being provided to or available from unrelated third
    parties; or fair and reasonable to us, taking into
    account the totality of the relationships between the parties
    involved (including other transactions that may be particularly
    favorable or advantageous to us).If our general partner does not seek approval from the conflicts
    committee and the board of directors of our general partner
    determines that the resolution or course of action taken with
    respect to the conflict of interest satisfies either of the
    standards set forth in the bullet points above, then it will be
    presumed that, in making its decision, the board of directors,
    which may include board members affected by the conflict of
    interest, acted in good faith, and in any proceeding brought by
    or on behalf of any limited partner or us, the person bringing
    or prosecuting such proceeding will have the burden of
    overcoming such presumption. These standards reduce the
    obligations to which our general partner would otherwise be held.     177




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DESCRIPTION
    OF THE COMMON UNITS The
    Units   Transfer
    Agent and Registrar  Duties
    
    surety bond premiums to replace lost or stolen certificates or
    to cover taxes and other governmental charges;
    special charges for services requested by a common
    unitholder; and
    other similar fees or charges.    Resignation
    or Removal
   Transfer
    of Common Units    
    represents that the transferee has the capacity, power and
    authority to become bound by our partnership agreement;
    automatically agrees to be bound by the terms and conditions of
    our partnership agreement; and
    gives the consents, waivers and approvals contained in our
    partnership agreement, such as the approval of all transactions
    and agreements that we are entering into in connection with our
    formation and this offering.   178




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179




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THE
    PARTNERSHIP AGREEMENT      
    with regard to distributions of available cash, please read
    Our Cash Distribution Policy and Restrictions on
    Distributions and Provisions of Our Partnership
    Agreement Relating to Cash Distributions;
    with regard to the fiduciary duties of our general partner,
    please read Conflicts of Interest and Fiduciary
    Duties;
    with regard to the transfer of common units, please read
    Description of the Common Units  Transfer of
    Common Units; and
    with regard to allocations of taxable income, taxable loss and
    other matters, please read Material Tax Consequences. Organization
    and Duration   Purpose     Cash
    Distributions   Capital
    Contributions   180




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Limited
    Voting Rights      
    during the subordination period, the approval of a majority of
    the outstanding common units, excluding those common units held
    by our general partner and its affiliates, and a majority of the
    outstanding subordinated units, each voting as a separate
    class; and
    after the subordination period, the approval of a majority of
    the outstanding common units.      Issuance of additional units
    
    No approval right. Please read  Issuance of
    Additional Securities.Amendment of the partnership agreement
    
    Certain amendments may be made by our general partner without
    the approval of the unitholders. Other amendments generally
    require the approval of a unit majority. Please read
     Amendment of the Partnership Agreement.Merger of our partnership or the sale of all or substantially
    all of our assets
    
    Unit majority, in certain circumstances. Please read
     Merger, Consolidation, Conversion, Sale or
    Other Disposition of Assets.Dissolution of our partnership
    
    Unit majority. Please read  Termination and
    Dissolution.Continuation of our business upon dissolution
    
    Unit majority. Please read  Termination and
    Dissolution.Withdrawal of our general partner
    
    Prior
    to          ,
    2021, under most circumstances, the approval of a majority of
    the common units, excluding common units held by our general
    partner and its affiliates, is required for the withdrawal of
    our general partner in a manner that would cause a dissolution
    of our partnership. Please read
     Withdrawal or Removal of Our General
    Partner.Removal of our general partner
    
    Not less than
    662/3%
    of the outstanding units, including units held by our general
    partner and its affiliates. Please read
     Withdrawal or Removal of Our General
    Partner.Transfer of our general partner interest
    
    Our general partner may transfer without a vote of our
    unitholders all, but not less than all, of its general partner
    interest in us to an affiliate or another person (other than an
    individual) in connection with its merger or consolidation with
    or into, or sale of all, or substantially all, of its assets, to
    such person. The approval of a majority of the common units,
    excluding common units held by our general partner and its
    affiliates, is required in other circumstances for a transfer of
    the general partner interest to a 181




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third-party prior
    to          ,
    2021. Please read  Transfer of General Partner
    Units.Transfer of incentive distribution rights
    
    No approval rights. Please read  Transfer of
    Incentive Distribution Rights.Transfer of ownership interests in our general partner
    
    No approval required. Please read  Transfer of
    Ownership Interests in Our General Partner. Applicable
    Law; Forum, Venue and Jurisdiction    
    arising out of or relating in any way to the partnership
    agreement (including any claims, suits or actions to interpret,
    apply or enforce the provisions of the partnership agreement or
    the duties, obligations or liabilities among limited partners or
    of limited partners to us, or the rights or powers of, or
    restrictions on, the limited partners or us);
    brought in a derivative manner on our behalf;
    asserting a claim of breach of a fiduciary duty owed by any
    director, officer or other employee of us or our general
    partner, or owed by our general partner, to us or the limited
    partners;
    asserting a claim arising pursuant to any provision of the
    Delaware Act; or
    asserting a claim governed by the internal affairs doctrine,   Limited
    Liability    
    to remove or replace our general partner;
    to approve some amendments to the partnership agreement; or
    to take other action under the partnership agreement     182




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Issuance
    of Additional Securities         183




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Amendment
    of the Partnership Agreement  General
    Prohibited
    Amendments
    
    enlarge the obligations of any limited partner without its
    consent, unless approved by at least a majority of the type or
    class of limited partner interests so affected; or
    enlarge the obligations of, restrict in any way any action by or
    rights of, or reduce in any way the amounts distributable,
    reimbursable or otherwise payable by us to our general partner
    or any of its affiliates without the consent of our general
    partner, which consent may be given or withheld in its sole
    discretion.    No
    Unitholder Approval
    
    a change in our name, the location of our principal place of
    business, our registered agent or our registered office;
    the admission, substitution, withdrawal or removal of partners
    in accordance with our partnership agreement;
    a change that our general partner determines to be necessary or
    appropriate for us to qualify or to continue our qualification
    as a limited partnership or other entity in which the limited
    partners have limited liability under the laws of any state or
    to ensure that neither we, nor any of our subsidiaries will be
    treated as an association taxable as a corporation or otherwise
    taxed as an entity for federal income tax purposes;
    a change in our fiscal year or taxable year and related changes;
    an amendment that is necessary, in the opinion of our counsel,
    to prevent us or our general partner or the directors, officers,
    agents or trustees of our general partner from in any manner
    being subjected to the provisions of the Investment Company Act
    of 1940, the Investment Advisors Act of 1940, or plan
    asset regulations adopted under the Employee Retirement
    Income Security Act of 1974, or ERISA, whether or not
    substantially similar to plan asset regulations currently
    applied or proposed; 184




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
    an amendment that our general partner determines to be necessary
    or appropriate for the authorization of additional partnership
    securities or rights to acquire partnership securities;
    any amendment expressly permitted in our partnership agreement
    to be made by our general partner acting alone;
    an amendment effected, necessitated or contemplated by a merger
    agreement that has been approved under the terms of our
    partnership agreement;
    any amendment that our general partner determines to be
    necessary or appropriate for the formation by us of, or our
    investment in, any corporation, partnership or other entity, as
    otherwise permitted by our partnership agreement;
    any amendment necessary to require our limited partners to
    provide a statement, certification or other evidence to us
    regarding whether such limited partner is subject to United
    States federal income taxation on the income generated by us and
    to provide for the ability of our general partner to redeem the
    units of any limited partner who fails to provide such
    statement, certification or other evidence;
    conversions into, mergers with or conveyances to another limited
    liability entity that is newly formed and has no assets,
    liabilities or operations at the time of the conversion, merger
    or conveyance other than those it receives by way of the
    conversion, merger or conveyance; or
    any other amendments substantially similar to any of the matters
    described in the clauses above.    
    do not adversely affect our limited partners (or any particular
    class of limited partners) in any material respect;
    are necessary or appropriate to satisfy any requirements,
    conditions or guidelines contained in any opinion, directive,
    order, ruling or regulation of any federal or state agency or
    judicial authority or contained in any federal or state statute;
    are necessary or appropriate to facilitate the trading of our
    limited partner interests or to comply with any rule,
    regulation, guideline or requirement of any securities exchange
    on which our limited partner interests are or will be listed for
    trading;
    are necessary or appropriate for any action taken by our general
    partner relating to splits or combinations of units under the
    provisions of our partnership agreement; or
    are required to effect the intent expressed in this prospectus
    or the intent of the provisions of the partnership agreement or
    are otherwise contemplated by our partnership agreement.  Opinion
    of Counsel and Unitholder Approval
     185




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Merger,
    Consolidation, Conversion, Sale or Other Disposition of
    Assets       Termination
    and Dissolution    
    the election of our general partner to dissolve us, if approved
    by the holders of a unit majority;
    there being no limited partners, unless we are continued without
    dissolution in accordance with applicable Delaware law;
    the entry of a decree of judicial dissolution of our
    partnership; or
    the withdrawal or removal of our general partner or any other
    event that results in its ceasing to be our general partner
    other than by reason of a transfer of its general partner
    interest in us in accordance with our partnership agreement or
    withdrawal or removal following approval and admission of a
    successor.   186




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
    the action would not result in the loss of limited liability
    under Delaware law of any limited partner; and
    neither our partnership nor any of our subsidiaries would be
    treated as an association taxable as a corporation or otherwise
    be taxable as an entity for federal income tax purposes upon the
    exercise of that right to continue (to the extent not already so
    treated or taxed). Liquidation
    and Distribution of Proceeds   Withdrawal
    or Removal of Our General Partner      2 3 1 3
 187




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
    the subordination period will end and all outstanding
    subordinated units will immediately convert into common units on
    a
    one-for-one
    basis;
    any existing arrearages in payment of the minimum quarterly
    distribution on the common units will be extinguished; and
    our general partner will have the right to convert its general
    partner interest and its incentive distribution rights into
    common units or to receive cash in exchange for those interests
    based on the fair market value of the interests at the time.         Transfer
    of General Partner Units    
    an affiliate of our general partner (other than an
    individual); or
    another entity as part of the merger or consolidation of our
    general partner with or into another entity or the transfer by
    our general partner of all or substantially all of its assets to
    another entity,     188




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Transfer
    of Incentive Distribution Rights   Transfer
    of Ownership Interests in Our General Partner   Change of
    Management Provisions   Limited
    Call Right    
    the highest cash price paid by either of our general partner or
    any of its affiliates for any limited partner interests of the
    class purchased within the 90 days preceding the date on
    which our general partner first mails notice of its election to
    purchase those limited partner interests; and
    the current market price as of the date three days before the
    date the notice is mailed.   Meetings;
    Voting     189




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Status as
    Limited Partner   Non-Citizen
    Assignees; Redemption     Non-Taxpaying
    Assignees; Redemption   190




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
    obtain proof of the U.S. federal income tax status of
    limited partners (and their owners, to the extent
    relevant); and
    permit us to redeem the units at their current market price held
    by any person whose tax status has or is reasonably likely to
    have a material adverse effect on our ability to operate our
    assets or generate revenues from our assets or who fails to
    comply with the procedures instituted by our general partner to
    obtain proof of the U.S. federal income tax status.   Indemnification    
    our general partner;
    any departing general partner;
    any person who is or was an affiliate of a general partner or
    any departing general partner;
    any person who is or was a director, officer, member, partner,
    fiduciary or trustee of any entity set forth in the preceding
    three bullet points;
    any person who is or was serving as a director, officer, member,
    partner, fiduciary or trustee of another person at the request
    of our general partner or any departing general partner; and
    any person designated by our general partner.   Reimbursement
    of Expenses     Books and
    Reports   191




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Right to
    Inspect Our Books and Records    
    a current list of the name and last known address of each
    partner;
    a copy of our tax returns;
    information as to the amount of cash, and a description and
    statement of the agreed value of any other property or services,
    contributed or to be contributed by each partner and the date on
    which each partner became a partner;
    copies of our partnership agreement, our certificate of limited
    partnership, related amendments and powers of attorney under
    which they have been executed;
    information regarding the status of our business and financial
    condition; and
    any other information regarding our affairs as is just and
    reasonable.   Registration
    Rights   192




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UNITS
    ELIGIBLE FOR FUTURE SALE      
    1.0% of the total number of the securities outstanding; or
    the average weekly reported trading volume of the common units
    for the four calendar weeks prior to the sale.        lock-up
 193




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MATERIAL
    TAX CONSEQUENCES           Partnership
    Status   194




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
    Neither we nor the operating company has elected or will elect
    to be treated as a corporation;
    For each taxable year of our existence, more than 90% of our
    gross income has been and will be income that Akin Gump Strauss
    Hauer & Feld LLP has opined or will opine is
    qualifying income within the meaning of
    Section 7704(d) of the Internal Revenue Code; and
    Each hedging transaction that we treat as resulting in
    qualifying income has been and will be appropriately identified
    as a hedging transaction pursuant to applicable Treasury
    Regulations, and has been and will be associated with oil,
    natural gas, or products thereof that are held or to be held by
    us in activities that Akin Gump Strauss Hauer & Feld
    LLP has opined or will opine result in qualifying income.       195




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Limited
    Partner Status       Tax
    Consequences of Unit Ownership  Flow-Through
    of Taxable Income
    Treatment
    of Distributions
    and/or
 196




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Ratio
    of Taxable Income to Distributions
    
    gross income from operations exceeds the amount required to make
    minimum quarterly distributions on all units, yet we only
    distribute the minimum quarterly distributions on all units;
    we make a future offering of common units and use the proceeds
    of the offering in a manner that does not produce substantial
    additional deductions during the period described above, such as
    to repay indebtedness outstanding at the time of this offering
    or to acquire property that is not eligible for depreciation or
    amortization for federal income tax purposes or that is
    depreciable or amortizable at a rate significantly slower than
    the rate applicable to our assets at the time of this offering;
    or
    legislation is passed in response to President Obamas
    Budget Proposal for Fiscal Year 2012 that would limit or repeal
    certain U.S. federal income tax preferences currently
    available to oil and gas exploration and production companies.
    Please read  Tax Treatment of
    Operations  Recent Legislative Developments.  Basis
    of Common Units
    Limitations
    on Deductibility of Losses
   197




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activity-by-activity
      Limitations
    on Interest Deductions
    
    interest on indebtedness properly allocable to property held for
    investment; 198




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
    our interest expense attributed to portfolio income; and
    the portion of interest expense incurred to purchase or carry an
    interest in a passive activity to the extent attributable to
    portfolio income.    Entity-Level Collections
    of Unitholder Taxes
    Allocation
    of Income, Gain, Loss and Deduction
     199




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
    his relative contributions to us;
    the interests of all the partners in profits and losses;
    the interest of all the partners in cash flow; and
    the rights of all the partners to distributions of capital upon
    liquidation.    Treatment
    of Short Sales
    
    any of our income, gain, loss or deduction with respect to those
    units would not be reportable by the unitholder;
    any cash distributions received by the unitholder as to those
    units would be fully taxable; and
    all of these distributions may be subject to ordinary income tax.    Alternative
    Minimum Tax
   200




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Tax
    Rates
      Section 754
    Election
    Regulation Section 1.167(c)-1(a)(6),
  non-amortizable Regulation Section 1.167(c)-1(a)(6),
 201




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Tax
    Treatment of Operations  Accounting
    Method and Taxable Year
    Depletion
    Deductions
   202




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203




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Deductions
    for Intangible Drilling and Development Costs
    60-month 60-month
        Deduction
    for U.S. Production Activities
  Form W-2
     204




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Form W-2 Form W-2
  Form W-2
  Lease
    Acquisition Costs
    Geophysical
    Costs
  24-month
  Operating
    and Administrative Costs
    Recent
    Legislative Developments
   205




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Initial
    Tax Basis, Depreciation and Amortization
          Valuation
    and Tax Basis of Our Properties
   Disposition
    of Common Units  Recognition
    of Gain or Loss
     206




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
    a short sale;
    an offsetting notional principal contract; or
    a futures or forward contract with respect to the partnership
    interest or substantially identical property.    Allocations
    Between Transferors and Transferees
   207




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Notification
    Requirements
    Constructive
    Termination
  Schedule K-1
 208




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Uniformity
    of Units  Regulation Section 1.167(c)-1(a)(6).
  Regulation Section 1.167(c)-1(a)(6),
 Tax-Exempt
    Organizations and Other Investors  non-U.S. person,
    Form W-8BEN
 209




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Administrative
    Matters  Information
    Returns and Audit Procedures
  Schedule K-1,
       210




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Nominee
    Reporting
    
    the name, address and taxpayer identification number of the
    beneficial owner and the nominee;
    a statement regarding whether the beneficial owner is:  
    a person that is not a U.S. person;
    a foreign government, an international organization or any
    wholly owned agency or instrumentality of either of the
    foregoing; or
    a tax-exempt entity;  
    the amount and description of units held, acquired or
    transferred for the beneficial owner; and
    specific information including the dates of acquisitions and
    transfers, means of acquisitions and transfers, and acquisition
    cost for purchases, as well as the amount of net proceeds from
    sales.    Accuracy-Related
    Penalties
      
    for which there is, or was, substantial
    authority; or
    as to which there is a reasonable basis and the pertinent facts
    of that position are disclosed on the return.     211




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Reportable
    Transactions
      
    accuracy-related penalties with a broader scope, significantly
    narrower exceptions, and potentially greater amounts than
    described above at  Accuracy-Related
    Penalties;
    for those persons otherwise entitled to deduct interest on
    federal tax deficiencies, nondeductibility of interest on any
    resulting tax liability; and
    in the case of a listed transaction, an extended statute of
    limitations.   State,
    Local and Other Tax Considerations   212




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213




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INVESTMENT
    IN MEMORIAL PRODUCTION PARTNERS LP BY EMPLOYEE BENEFIT
    PLANS  non-U.S. or
  
    whether the investment is prudent under
    Section 404(a)(1)(B) of ERISA and any other applicable
    Similar Laws;
    whether in making the investment, the plan will satisfy the
    diversification requirements of Section 404(a)(1)(C) of
    ERISA and any other applicable Similar Laws;
    whether the investment will result in recognition of unrelated
    business taxable income by the plan and, if so, the potential
    after-tax investment return. Please read Material Tax
    Consequences  Tax-Exempt Organizations and Other
    Investors; and
    whether making such an investment will comply with the
    delegation of control and prohibited transaction provisions of
    ERISA, the Internal Revenue Code and any other applicable
    Similar Laws.          
    the equity interests acquired by the employee benefit plan are
    publicly offered securities  i.e., the equity
    interests are widely held by 100 or more investors independent
    of the issuer and each other, are freely transferable and are
    registered under certain provisions of the federal securities
    laws;
    the entity is an operating company, 
    i.e., it is primarily engaged in the production or sale of a
    product or service, other than the investment of capital, either
    directly or through a majority-owned subsidiary or
    subsidiaries; or 214




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
    there is no significant investment by benefit plan investors,
    which is defined to mean that less than 25% of the value of each
    class of equity interest is held by the employee benefit plans
    referred to above that are subject to ERISA and IRAs and other
    similar vehicles that are subject to Section 4975 of the
    Internal Revenue Code.     215




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UNDERWRITING    Number ofUnderwriter

Common UnitsCitigroup Global Markets Inc.Raymond James & Associates, Inc.Wells Fargo Securities, LLCJ.P. Morgan Securities LLCTotal           lock-up 180-day 180-day 16-day 180-day 18-day
 216




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lock-up lock-up
  180-day
        Paid by Memorial Production Partners LPNo Exercise

Full ExercisePer common unit

$



$Total

$



$       
    Short sales involve secondary market sales by the underwriters
    of a greater number of common units than they are required to
    purchase in this offering.  
    Covered short sales are sales of common units in an
    amount up to the number of common units represented by the
    underwriters option to purchase additional common units.
    Naked short sales are sales of common units in an
    amount in excess of the number of common units represented by
    the underwriters option to purchase additional common
    units.  
    Covering transactions involve purchases of common units either
    pursuant to the underwriters option to purchase additional
    common units or in the open market after the distribution has
    been completed in order to cover short positions. 217




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
    To close a naked short position, the underwriters must purchase
    common units in the open market after the distribution has been
    completed. A naked short position is more likely to be created
    if the underwriters are concerned that there may be downward
    pressure on the price of the common units in the open market
    after pricing that could adversely affect investors who purchase
    in this offering.
    To close a covered short position, the underwriters must
    purchase common units in the open market after the distribution
    has been completed or must exercise the underwriters
    option to purchase additional common units. In determining the
    source of common units to close the covered short position, the
    underwriters will consider, among other things, the price of
    common units available for purchase in the open market as
    compared to the price at which they may purchase common units
    through the underwriters option to purchase additional
    common units.  
    Stabilizing transactions involve bids to purchase common units
    so long as the stabilizing bids do not exceed a specified
    maximum.  over-the-counter
      180-day 90-day
     218




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Notice to
    Prospective Investors in the European Economic Area    
    to any legal entity which is a qualified investor as defined in
    the Prospectus Directive;
    to fewer than 100 or, if the Relevant Member State has
    implemented the relevant provision of the 2010 PD Amending
    Directive, 150, natural or legal persons (other than qualified
    investors as defined in the Prospectus Directive), as permitted
    under the Prospectus Directive, subject to obtaining the prior
    consent of the relevant Dealer or Dealers nominated by the
    Issuer for any such offer; or
    in any other circumstances falling within Article 3(2) of
    the Prospectus Directive.    2003/71/EC
   Notice to
    Prospective Investors in the United Kingdom       219




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Notice to
    Prospective Investors in Germany  (Wertpapierprospektgesetz) (Verkaufsprospektgesetz) (Investmentgesetz) (Bundesanstalt
    für Finanzdienstleistungsaufsicht  BaFin)
   Notice to
    Prospective Investors in the Netherlands  (gekwalificeerde beleggers) (Wet op het financieel toezicht)
 Notice to
    Prospective Investors in Switzerland     220




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##### Table of Contents



VALIDITY
    OF THE COMMON UNITS   EXPERTS           WHERE YOU
    CAN FIND MORE INFORMATION  Form S-l 1-800-SEC-0330. http://www.sec.gov.
   221




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##### Table of Contents



FORWARD-LOOKING
    STATEMENTS    
    business strategies;
    ability to replace the reserves we produce through drilling and
    property acquisitions;
    drilling locations;
    oil and natural gas reserves;
    technology;
    realized oil and natural gas prices;
    production volumes;
    lease operating expenses;
    general and administrative expenses;
    future operating results;
    cash flows and liquidity;
    availability of drilling and production equipment;
    availability of oil field labor;
    capital expenditures;
    availability and terms of capital;
    marketing of oil and natural gas;
    general economic conditions;
    competition in the oil and natural gas industry;
    effectiveness of risk management activities;
    environmental liabilities;
    counterparty credit risk;
    governmental regulation and taxation;
    developments in oil-producing and natural-gas producing
    countries; and
    plans, objectives, expectations and intentions.   222




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223




---



##### 



INDEX TO
    FINANCIAL STATEMENTS  
  MEMORIAL PRODUCTION PARTNERS LPUnaudited Pro Forma Combined Financial Statements:Introduction


F-2Unaudited Pro Forma Combined Balance Sheet as of
    March 31, 2011


F-4Unaudited Pro Forma Combined Statement of
    Operations for the Year Ended December 31, 2010


F-5Unaudited Pro Forma Combined Statement of
    Operations for the Three Months Ended March 31, 2011


F-6Notes to Unaudited Pro Forma Combined Financial
    Statements


F-7Historical Balance Sheet:Report of Independent Registered Public
    Accounting Firm


F-16Balance Sheet as of April 27, 2011


F-17Note to Balance Sheet


F-18PREDECESSORUnaudited Historical Combined Financial Statements as of
    March 31, 2011 and December 31, 2010 and for the Three
    Months Ended March 31, 2011 and March 31, 2010:Combined Balance Sheets


F-19Combined Statements of Operations


F-20Combined Statement of Changes in Partners
    Capital


F-21Combined Statements of Cash Flows


F-22Notes to Combined Financial Statements


F-23Historical Combined Financial Statements as of December 31,
    2010 and 2009 and for the Years Ended December 31, 2010,
    2009 and 2008:Report of Independent Registered Public
    Accounting Firm


F-38Combined Balance Sheets


F-39Combined Statements of Operations


F-40Combined Statements of Changes in Partners
    Capital


F-41Combined Statements of Cash Flows


F-42Notes to the Combined Financial Statements


F-43FOREST ACQUISITION FINANCIAL STATEMENTSHistorical Statements of Revenues and Direct Operating Expenses
    for the years ended December 31, 2009 and 2008 and for the
    Six Months Ended June 30, 2010 (unaudited):Report of Independent Registered Public
    Accounting Firm


F-65Statements of Revenues and Direct Operating
    Expenses


F-66Notes to Statements of Revenues and Direct
    Operating Expenses


F-67BP ACQUISITION FINANCIAL STATEMENTSHistorical Statements of Revenues and Direct Operating Expenses
    for each of the three years in the period ended
    December 31, 2010, and the Three Months Ended
    March 31, 2011 and March 31, 2010 (unaudited):Report of Independent Auditors


F-72Statements of Revenues and Direct Operating
    Expenses


F-73Notes to Statements of Revenues and Direct
    Operating Expenses


F-74   F-1




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##### Table of Contents



MEMORIAL
    PRODUCTION PARTNERS LP



UNAUDITED
    PRO FORMA COMBINED FINANCIAL STATEMENTS Introduction      
    oil and natural gas properties and related assets acquired by
    the Predecessor from Forest Oil Corporation (Forest
    Oil) on June 30, 2010;
    oil and natural gas properties and related assets acquired by
    the Predecessor from BP America Production Company
    (BP) on May 31, 2011; and
    40% of the oil and natural gas properties and related assets
    acquired by WHT Energy Partners LLC (WHT), a
    subsidiary of Memorial Resource, from a third party on
    April 8, 2011 (the Carthage Properties).    The Contribution.
  The Offering.
     F-2




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F-3




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##### Table of Contents



MEMORIAL
    PRODUCTION PARTNERS LP



UNAUDITED
    PRO FORMA COMBINED BALANCE SHEET  AS OF MARCH
    31, 2011  (In
    thousands)
  PartnershipPartnership


Predecessor


Pre-offering


Offering


ProPredecessor


Properties


Retained


Partnership


Related


Forma asHistorical


Adjustments


Operations


Pro Forma


Adjustments


Adjusted(a)


(b)ASSETSCurrent assets:Cash and cash equivalents

$
2,130


$



$
(2,130
)

$



$
130,000
(c)

$
250,000
(d)(150,189
)(e)(189,811
)(e)Accounts receivable:


















(40,000
)(f)Oil and natural gas sales


5,895







(260
)


5,635







5,635Joint interest owners and other


3,848







(13
)


3,835







3,835Short-term derivative instruments


2,694











2,694







2,694Prepaid expenses and other current assets


798







(12
)


786







786Total current assets


15,365







(2,415
)


12,950







12,950Property and equipment, at cost:Oil and natural gas properties, successful efforts method


321,144



202,523



(17,725
)


505,942







505,942Other


2,781







(1,106
)


1,675







1,675Accumulated depreciation, depletion and impairment


(97,675
)






8,194



(89,481
)






(89,481
)Oil and natural gas properties, net


226,250



202,523



(10,637
)


418,136







418,136Long-term derivative instruments


2,142











2,142







2,142Other long-term assets


1,285







(61
)


1,224



1,600
(f)


1,879(945
)(i)Total assets

$
245,042


$
202,523


$
(13,113
)

$
434,452


$
655


$
435,107LIABILITIES AND PARTNERS CAPITALCurrent liabilities:Accounts payable

$
5,097


$



$
(240
)

$
4,857


$



$
4,857Revenues payable


3,639







(1,357
)


2,282







2,282Accrued liabilities


3,850







(46
)


3,804







3,804Current portion of long-term debt


78







(6
)


72



(72
)(e)


Short-term derivative instruments


186











186







186Asset retirement obligations


25



478







503







503Total current liabilities


12,875



478



(1,649
)


11,704



(72
)


11,632Long-term debt


112,506



84,051



(6,818
)


189,739



130,000
(c)


130,000(189,739
)(e)Deferred tax liabilities


225











225







225Asset retirement obligations


11,073



3,953



(594
)


14,432







14,432Long-term derivative instruments


275











275







275Other long-term liabilities


49







(49
)










Total liabilities


137,003



88,482



(9,110
)


216,375



(59,811
)


156,564Partners capital


108,039



114,041



(4,003
)


218,077



250,000
(d)


278,543(150,189
)(e)(38,400
)(f)(945
)(i)Total liabilities and partners capital

$
245,042


$
202,523


$
(13,113
)

$
434,452


$
655


$
435,107    F-4




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##### Table of Contents



MEMORIAL
    PRODUCTION PARTNERS LP



UNAUDITED
    PRO FORMA COMBINED STATEMENT OF OPERATIONS

FOR
    THE YEAR ENDED DECEMBER 31, 2010  (In
    thousands, except per unit amounts)
  Partnership


Predecessor


Pre-Offering


Offering


PartnershipPredecessor


Properties


Retained


Partnership


Related


Pro FormaHistorical


Adjustments


Operations


Pro Forma


Adjustments


as Adjusted(g)


(b)Revenues:Oil & natural gas sales

$
37,308


$
52,234


$
(1,780
)

$
87,762


$



$
87,762Other income


1,433







(29
)


1,404







1,404Total revenues


38,741



52,234



(1,809
)


89,166







89,166Costs and expenses:Lease operating


13,974



10,280



(1,202
)


23,052







23,052Exploration


39







(3
)


36







36Production taxes


2,112



5,432



(157
)


7,387







7,387Depreciation, depletion and amortization


20,066



16,640



(1,934
)


34,772







34,772Impairment of proved oil and natural gas properties


11,800







(2,291
)


9,509







9,509General and administrative


6,116







(297
)


5,819







5,819Accretion


663



448



(39
)


1,072







1,072(Gain)/loss on derivative instruments


(10,264
)










(10,264
)






(10,264
)Gain on sale of properties


(1
)






1











Other, net


890











890







890Total costs and expenses


45,395



32,800



(5,922
)


72,273







72,273Operating (loss) income


(6,654
)


19,434



4,113



16,893







16,893Interest expense


(4,438
)






294



(4,144
)


(3,965
)(h)


(4,365
)4,144
(h)(400
)(i)Income tax expense


(225
)










(225
)






(225
)Net (loss) income

$
(11,317
)

$
19,434


$
4,407


$
12,524


$
(221
)

$
12,303   General partners interest in net income

$Limited partners interest in net income

$Net income per limited partner units:Common units (basic)

$Subordinated units

$Common units (diluted)

$Weighted limited partner units outstanding:Common units (basic)

$Subordinated units

$Common units (diluted)

$    F-5




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##### Table of Contents



MEMORIAL
    PRODUCTION PARTNERS LP



UNAUDITED
    PRO FORMA COMBINED STATEMENT OF OPERATIONS

FOR
    THE THREE MONTHS ENDED MARCH 31, 2011  (In
    thousands, except per unit amounts)
  PartnershipPartnership


Predecessor


Pre-Offering


Offering


ProPredecessor


Properties


Retained


Partnership


Related


Forma asHistorical


Adjustments


Operations


Pro Forma


Adjustments


Adjusted(g)


(b)Revenues:Oil & natural gas sales

$
11,641


$
9,440


$
(433
)

$
20,648


$



$
20,648Other income


103







(4
)


99







99Total revenues


11,744



9,440



(437
)


20,747







20,747Costs and expenses:Lease operating


5,170



1,843



(328
)


6,685







6,685Exploration






















Production taxes


693



1,036



(26
)


1,703







1,703Depreciation, depletion and amortization


4,450



3,052



(476
)


7,026







7,026Impairment of proved oil and natural gas properties






















General and administrative


1,474







(75
)


1,399







1,399Accretion


210



78



(12
)


276







276(Gain)/loss on derivative instruments


703











703







703Gain on sale of properties


(8
)






8











Other, net






















Total costs and expenses


12,692



6,009



(909
)


17,792







17,792Operating (loss) income


(948
)


3,431



472



2,955







2,955Interest expense


(1,035
)






62



(973
)


(992
)(h)


(1,092
)973
(h)(100
)(i)Net (loss) income

$
(1,983
)

$
3,431


$
534


$
1,982


$
(119
)

$
1,863   General partners interest in net income

$Limited partners interest in net income

$Net income per limited partner units:Common units (basic)

$Subordinated units

$Common units (diluted)

$Weighted limited partner units outstanding:Common units (basic)

$Subordinated units

$Common units (diluted)

$    F-6




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##### Table of Contents



MEMORIAL
    PRODUCTION PARTNERS LP



NOTES TO
    UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS  Note 1 
    Basis of
    Presentation, the Offering, and Other Transactions          
    The sale and contribution to the Partnership of oil and natural
    gas properties and related assets owned by the Predecessor,
    including:  
    oil and natural gas properties and related assets acquired by
    the Predecessor from Forest Oil on June 30, 2010; and  
    oil and natural gas properties and related assets acquired by
    the Predecessor from BP on May 31, 2011;  
    The sale and contribution to the Partnership of 40% of the
    Carthage Properties acquired by the Predecessor through WHT from
    a third party on April 8, 2011;
    The contribution by the Predecessor and WHT to the Partnership
    of certain derivative contracts, which will be used to manage
    exposure to oil and natural gas price volatility related to the
    production from the Partnership Properties;
    The retention by the Predecessor of certain oil and natural gas
    interests and all other assets, liabilities and operations not
    sold or contributed to the Partnership;
    The issuance by the Partnership
    of          
    common units
    and          
    subordinated units and the payment of
    $      million in cash as
    consideration for the sale and contribution of the properties
    noted above; and
    The contribution to the Partnership by the general partner of
    the Partnership of $     in cash and
    the issuance
    of          
    general partner units to the general partner in respect of that
    contribution.      
    The issuance and sale by the Partnership
    of          
    common units to the public in the initial public offering at an
    assumed initial public offering price of
    $      per unit, resulting in gross
    proceeds to the Partnership of $250 million, before
    deduction of estimated underwriting discounts, a structuring fee
    and estimated offering expenses of
    $      million;
    Borrowings by the Partnership of $130 million under a new
    revolving credit facility (if the net proceeds from this
    offering increase or decrease, then our borrowing under our new
    revolving credit facility would correspondingly decrease or
    increase, respectively); and F-7




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##### Table of Contents



MEMORIAL
    PRODUCTION PARTNERS LP
  NOTES TO
    UNAUDITED PRO FORMA COMBINED FINANCIAL
    STATEMENTS  (Continued)
   
    The contribution to the Partnership by the general partner of
    the Partnership of $      in cash and
    the issuance
    of          
    general partner units to the general partner in respect of that
    contribution.  Note 2 
    Pro Forma
    Adjustments and Assumptions  Unaudited
    pro forma combined balance sheet
    Adjustments


Adjustmentsfor Carthage


for BP


PartnershipProperties


Properties


PropertiesAcquisition


Acquisition


Adjustments(1)


(2)(In thousands)AssetsCurrent assets:Cash and cash equivalents

$



$



$
Accounts receivable:Oil and natural gas sales










Joint interest owners and other










Short-term derivative instruments










Prepaid expenses and other current assets










Total current assets










Property and equipment, at cost:Oil and natural gas properties, successful efforts method


124,292



79,862



202,523



(1,631
)


Other










Less accumulated depreciation, depletion and impairment










Oil and natural gas properties, net


124,292



78,231



202,523Long-term derivative instruments










Other long-term assets










Total assets

$
124,292


$
78,231


$
202,523Liabilities and Partners CapitalCurrent liabilities:Accounts payable

$



$



$
Revenues payable










Accrued liabilities










Current portion of long-term debt










Short-term derivative instruments










Asset retirement obligations






478



478Total current liabilities






478



478Long-term debt


71,189



12,862



84,051Deferred tax liability










Asset retirement obligations


3,181



772



3,953Long-term derivative instruments










Other long-term liabilities










Total liabilities


74,370



14,112



88,482Partners capital


49,922



64,119



114,041Total liabilities and partners capital

$
124,292


$
78,231


$
202,523     (1)
    
    On April 8, 2011, WHT purchased certain oil and natural gas
    properties from a third party for approximately
    $302.8 million, of which 40% is being sold and contributed
    to the Partnership upon closing of the Offering. The
    Partnerships share of WHTs purchase price is
    allocated to oil and natural F-8




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##### Table of Contents



MEMORIAL
    PRODUCTION PARTNERS LP
  NOTES TO
    UNAUDITED PRO FORMA COMBINED FINANCIAL
    STATEMENTS  (Continued)
  gas properties in the amount of $124.3 million and to a
    liability of $3.2 million for the assumption of future
    asset retirement obligations. The WHT properties to be sold and
    contributed to the Partnership are burdened by approximately
    $71.2 million in indebtedness incurred by WHT in connection
    with the acquisition of such properties from a third party. A
    portion of the cash proceeds paid to WHT by the Partnership in
    respect of such sale and contribution will be used to repay such
    indebtedness.(2)
    
    On May 31, 2011, the Predecessor purchased interests in
    wells located in Duval, Jim Hogg, McMullen and Webb counties
    from BP in exchange for a combination of approximately
    $12.9 million in cash and the Predecessors interest
    in the Nueces Field of the Eagle Ford Shale, which consisted
    primarily of acreage. The preliminary purchase price allocation
    based on the fair value of the assets obtained is allocated to
    oil and natural gas properties in the amount of
    $79.9 million and to a liability of $1.2 million for
    the assumption of future asset retirement obligations.
    Additionally, the properties exchanged by the Predecessor
    related to this transaction in the amount of $1.6 million
    are reflected as a reduction in oil and natural gas properties.                   F-9




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##### Table of Contents



MEMORIAL
    PRODUCTION PARTNERS LP
  NOTES TO
    UNAUDITED PRO FORMA COMBINED FINANCIAL
    STATEMENTS  (Continued)
  Unaudited
    pro forma statements of operations
    Year
    Ended December 31, 2010
  Forest


Carthage


BPProperties


Properties


PropertiesRevenues &


Revenues &


Revenues &


AdditionalDirect


Direct


Direct


Adjustments


PartnershipOperating


Operating


Operating


for Property


PropertiesExpenses


Expenses


Expenses


Acquisitions


Adjustments(6)


(1)


(2)(In thousands)Revenues:Oil & natural gas sales

$
8,668


$
64,738


$
18,896


$
(37,005
)(3)

$
52,234(3,063
)(7)Other income


















Total revenues


8,668



64,738



18,896



(40,068
)


52,234Costs and expenses:Lease operating


1,975



9,830



4,373



(5,898
)(3)


10,280Transportation






3,063







(3,063
)(7)Exploration


















Production taxes


882



4,799



2,630



(2,879
)(3)


5,432Depreciation, depletion and amortization














4,430
(6)


16,6404,976
(4)7,234
(5)Impairment of proved oil and natural gas properties


















General and administrative


















Accretion














148
(6)


448239
(4)61
(5)(Gain)/loss on derivative instruments


















Gain on sale of properties


















Other, net


















Total costs and expenses


2,857



17,692



7,003



5,248



32,800Operating (loss) income


5,811



47,046



11,893



(45,316
)


19,434Interest expense


















Net (loss) income

$
5,811


$
47,046


$
11,893


$
(45,316
)

$
19,434  F-10




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##### Table of Contents



MEMORIAL
    PRODUCTION PARTNERS LP
  NOTES TO
    UNAUDITED PRO FORMA COMBINED FINANCIAL
    STATEMENTS  (Continued)
  Three
    Months Ended March 31, 2011
  Carthage


BPProperties


Properties


AdditionalRevenues &


Revenues &


AdjustmentsDirect


Direct


for


PartnershipOperating


Operating


Property


PropertiesExpenses


Expenses


Acquisitions


Adjustments(1)


(2)(In thousands)Revenues:Oil & natural gas sales

$
15,069


$
3,732


$
(8,563
)(3)

$
9,440(798
)(7)Other income














Total revenues


15,069



3,732



(9,361
)


9,440Costs and expenses:Lease operating


2,124



993



(1,274
)(3)


1,843Transportation


798







(798
)(7)


Exploration














Production taxes


1,142



579



(685
)(3)


1,036Depreciation, depletion and amortization










1,244
(4)


3,0521,808
(5)Impairment of proved oil and natural gas properties














General and administrative














Accretion










62
(4)


78







16
(5)


(Gain)/loss on derivative instruments














Gain on sale of properties














Other, net














Total costs and expenses


4,064



1,572



373



6,009Operating (loss) income


11,005



2,160



(9,734
)


3,431Interest expense














Net (loss) income

$
11,005


$
2,160


$
(9,734
)

$
3,431     (1)
    
    Adjustments reflect the pro forma revenues and direct operating
    expenses of the properties acquired by WHT on April 8,
    2011, as noted above. Historical lease operating statements by
    individual asset were used as the basis for the revenues and
    direct operating expenses.(2)
    
    Adjustments reflect the pro forma revenues and direct operating
    expenses of the BP properties acquired by the Predecessor on
    May 31, 2011, as noted above. Historical lease operating
    statements by individual asset were used as the basis for the
    revenues and direct operating expenses.(3)
    
    Pro forma adjustments to reflect the 60% of the revenues and
    direct operating expenses associated with the properties
    acquired by WHT on April 8, 2011 that are not being sold
    and contributed to the Partnership in the Contribution. These
    adjustments are net of the reclassification described in
    footnote (7) below.(4)
    
    Pro forma adjustments to reflect the depletion and depreciation
    on property and equipment and the accretion expense on asset
    retirement obligations associated with the Carthage Properties,
    the Partnerships 40% share of the properties acquired by
    WHT on April 8, 2011. F-11




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##### Table of Contents



MEMORIAL
    PRODUCTION PARTNERS LP
  NOTES TO
    UNAUDITED PRO FORMA COMBINED FINANCIAL
    STATEMENTS  (Continued)
   (5)
    
    Pro forma adjustments to reflect the depletion and depreciation
    on property and equipment and the accretion expense on asset
    retirement obligations associated with the BP properties
    acquired by the Predecessor.(6)
    
    Pro forma adjustments to reflect the depletion and depreciation
    on property and equipment and the accretion expense on asset
    retirement obligations for the period January 1, 2010
    through June 30, 2010 associated with the Forest Oil
    properties acquired by the Predecessor. On June 30, 2010,
    the Predecessor purchased certain oil and natural gas properties
    from Forest Oil for approximately $65.9 million. The actual
    results of the Forest Oil properties acquired are included in
    the Predecessors statement of operations for the periods
    subsequent to June 30, 2010. Accordingly, the pro forma
    combined statement of operations for the year ended
    December 31, 2010 is only adjusted for the revenues and
    operating expenses of the Forest Oil properties from
    January 1, 2010 to June 30, 2010.(7)
    
    Amounts represent historical transportation and marketing costs
    related to the Carthage Properties for the three months ended
    March 31, 2011 and the year ended December 31, 2010,
    respectively. The seller of the Carthage Properties previously
    recorded these amounts within expenses, as they paid such
    amounts on a gross basis to a third-party transportation and
    marketing company. However, WHT receives a wellhead price from
    the third-party purchasers that is net of transportation and
    marketing costs, and therefore, records these costs on a net
    basis within revenue. As a result, all transportation and
    marketing expenses associated with the properties acquired by
    WHT on April 8, 2011 have been reclassified from expenses
    to within revenue on the pro forma combined statements of
    operations to reflect the Partnerships net presentation of
    such costs subsequent to the acquisition of the Carthage
    Properties but prior to the adjustments shown in
    footnote (3) above.      Note 3 
    Pro Forma
    Net Income Per Limited Partner Unit    Note 4 
    Pro Forma
    Standardized Measure of Discounted Future Net Cash
    Flows  Estimated
    Quantities of Proved Oil and Natural Gas Reserves
   F-12




---



##### Table of Contents



MEMORIAL
    PRODUCTION PARTNERS LP
  NOTES TO
    UNAUDITED PRO FORMA COMBINED FINANCIAL
    STATEMENTS  (Continued)
          Proved ReservesEquivalentOil (MBbls)

Gas (MMcf)

NGL (MBbls)

(MMcfe)Proved reserves, December 31, 2009


1,794



196,864



4,224



232,972Extensions and discoveries


60



7,603



211



9,229Purchase of minerals in place


259



78,046







79,600Production


(107
)


(16,713
)


(272
)


(18,985
)Sale of minerals in place














Revision of previous estimates


(4
)


19,876



339



21,881Proved reserves, December 31, 2010


2,002



285,676



4,502



324,697   first-day-of-the-month
   F-13




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##### Table of Contents



MEMORIAL
    PRODUCTION PARTNERS LP
  NOTES TO
    UNAUDITED PRO FORMA COMBINED FINANCIAL
    STATEMENTS  (Continued)
    Standardized
    Measure of Discounted Future Net Cash Flows Relating to Oil and
    Gas Reserves
  Extractive Activities  Oil and Gas
    
    future costs and selling prices will probably differ from those
    required to be used in these calculations;
    due to future market conditions and governmental regulations,
    actual rates of production in future years may vary
    significantly from the rate of production assumed in the
    calculations;
    a 10% discount rate may not be reasonable as a measure of the
    relative risk inherent in realizing future net oil and natural
    revenues; and
    the effects of federal income taxes have been excluded.    Non-Predecessor

Contribution

Partnership

Pro Forma

Pro FormaHistorical

Adjustments

Properties

Adjustments (1)

PartnershipFuture cash inflows

$
780,477


$
750,264


$
18,491


$
41,345


$
1,553,595Future production costs


(291,486
)


(250,185
)


(8,808
)


(32,628
)


(565,491
)Future development costs


(68,046
)


(40,321
)


(3,686
)






(104,681
)Future income tax expense(2)


(5,463
)


(5,252
)


(129
)


(289
)


(10,875
)Future net cash flows before 10% discount


415,482



454,506



5,868



8,428



872,54810% annual discount for estimated timing of cash flows


(231,667
)


(276,336
)


(2,540
)


(7,887
)


(513,350
)Standardized measure of discounted future net cash flows

$
183,815


$
178,170


$
3,328


$
541


$
359,198     (1)
    
    Consists of revisions to previous estimates of proved reserves
    related primarily to oil and gas properties acquired by the
    Predecessor from BP in 2011.(2)
    
    Represents future amounts owed associated with Texas margin tax. F-14




---



##### Table of Contents



MEMORIAL
    PRODUCTION PARTNERS LP
  NOTES TO
    UNAUDITED PRO FORMA COMBINED FINANCIAL
    STATEMENTS  (Continued)
   Changes
    in Standardized Measure of Discounted Future Net Cash Flows
    Relating to Proved Oil and Natural Gas Reserves
    December 31, 2010(In thousands)Beginning of year

$
215,970Sale of oil and natural gas produced, net of production costs


(52,623
)Purchase of minerals in place


104,729Sales of minerals in place


Extensions and discoveries


8,526Changes in income taxes, net


(1,747
)Changes in prices and costs


57,481Previously estimated development costs incurred


2,229Net changes in future development costs


(4,948
)Revisions of previous quantities


15,646Accretion of discount


21,584Changes in production rates and other


(7,649
)End of year

$
359,198  F-15




---



##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM              F-16




---



##### Table of Contents



MEMORIAL
    PRODUCTION PARTNERS LPBALANCE SHEET AS OF APRIL 27,
    2011
  April 27, 2011AssetsCash


Total assets

$
Partners capitalLimited partners capital


999General partners capital


1Receivable from partners


(1,000
)Total partners capital

$
    F-17




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##### Table of Contents



MEMORIAL
    PRODUCTION PARTNERS LP
 NOTE TO BALANCE SHEET  Note 1 
    Organization     F-18




---



##### Table of Contents



PREDECESSOR COMBINED
    BALANCE SHEETS AS OF MARCH 31, 2011 AND
    DECEMBER 31, 2010  March 31, 2011


December 31, 2010(unaudited)(In thousands)ASSETSCurrent assets:Cash and cash equivalents

$
2,130


$
5,654Accounts receivable:Oil and natural gas sales


5,895



6,175Joint interest owners and other


3,848



3,848Short-term derivative instruments


2,694



3,791Prepaid expenses and other current assets


798



771Total current assets


15,365



20,239Property and equipment, at cost:Oil and natural gas properties, successful efforts method


321,144



314,975Other


2,781



2,553323,925



317,528Accumulated depreciation, depletion and impairment


(97,675
)


(93,224
)Oil and natural gas properties, net


226,250



224,304Long-term derivative instruments


2,142



2,699Other long-term assets


1,285



1,298Total assets

$
245,042


$
248,540LIABILITIES AND PARTNERS CAPITALCurrent liabilities:Accounts payable

$
5,097


$
8,482Revenues payable


3,639



3,564Accrued liabilities


3,850



3,874Current portion of long-term debt


78



69Short-term derivative instruments


186



109Asset retirement obligations


25



25Total current liabilities


12,875



16,123Long-term debt


112,506



115,359Deferred tax liabilities


225



225Asset retirement obligations


11,073



10,867Long-term derivative instruments


275



109Other long-term liabilities


49



56Total liabilities


137,003



142,739Commitments and contingencies (Note 10)Partners capital


108,039



105,801Total liabilities and partners capital

$
245,042


$
248,540    F-19




---



##### Table of Contents



PREDECESSOR
  COMBINED STATEMENTS OF OPERATIONS
     FOR THE
 THREE
    MONTHS ENDED MARCH 31, 2011 AND 2010
  2011


2010(Unaudited)(In thousands)Revenues:Oil & natural gas sales

$
11,641


$
7,879Other income


103



67Total revenues


11,744



7,946Costs and expenses:Lease operating


5,170



2,220Production and ad valorem taxes


693



509Depreciation, depletion and amortization


4,450



4,352Impairment of proved oil and natural gas properties






1,691General and administrative


1,474



1,108Accretion


210



64(Gain)/loss on derivative instruments


703



(6,636)Gain on sale of properties


(8)



Total costs and expenses


12,692



3,308Operating (loss) income


(948)



4,638Interest expense


(1,035)



(606)Net (loss) income

$
(1,983)


$
4,032    F-20




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##### Table of Contents



PREDECESSOR
  COMBINED
    STATEMENT OF PARTNERS CAPITAL FOR THE
 THREE
    MONTHS ENDED MARCH 31, 2011
  Total PartnersCapital(Unaudited)(In thousands)Balance December 31, 2010

$
105,801Contributions from partners


4,221Distributions to partners


0Net income


(1,983
)Balance March 31, 2011

$
108,039    F-21




---



##### Table of Contents



PREDECESSOR
  COMBINED
    STATEMENTS OF CASH FLOWS FOR  THE
 THREE
    MONTHS ENDED MARCH 31, 2011 AND 2010
  2011


2010(Unaudited)(In thousands)Cash flows from operating activities:Net (loss) income

$
(1,983)


$
4,032Adjustments to reconcile net (loss) income to net cash provided
    by operating activities:Depreciation, depletion, and amortization


4,450



4,352Impairment of proved oil and natural gas properties






1,691Unrealized (gain) loss on derivatives


1,898



(5,703)Amortization of loan origination fees


85



60Accretion


210



64Gain on sale of properties


(8)



Changes in operating assets and liabilities:Accounts receivable


281



(1,470)Prepaid expenses and other assets


(100)



555Accounts payable


(1,879)



818Revenue payable


76



(717)Accrued liabilities


(25)



339Other


(6)



(86)Net cash provided by operating activities

$
2,999


$
3,935Cash flows from investing activities:Acquisition of oil and natural gas properties


(1,650)



(8,220)Additions to oil and gas properties


(6,021)



(3,681)Additions to other property and equipment


(227)



(100)Proceeds from the sale of oil and gas properties






1,400Net cash used by investing activities

$
(7,898)


$
(10,601)Cash flows from financing activities:Advances on revolving credit facility


47



1,289Payments on revolving credit facility


(2,893)



Contributed capital


4,221



8,145Net cash provided by financing activities


1,375



9,434Net increase (decrease) in cash

$
(3,524)


$
2,768Cash and cash equivalents, beginning of period

$
5,654


$
5,297Cash and cash equivalents, end of period

$
2,130


$
8,065Supplemental disclosure of cash flows:Cash paid for interest

$
987


$
568    F-22




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS
  Note 1 
    Organization  General
      
    BlueStone Natural Resources, LLC (BlueStone) is a
    Delaware limited liability company formed in January 2006 to
    engage in the acquisition, development, production and
    exploration and sale of oil and natural gas. BlueStone is a
    wholly owned subsidiary of BlueStone Natural Resources Holdings,
    LLC (Holdings), whose sole purpose is to provide
    financing for BlueStone. BlueStone owns oil and natural gas
    producing properties in Texas. Prior to the Offering, Memorial
    Resource owned an 89.45% interest in BlueStone and certain
    members of BlueStones management owned a 10.55% interest.
    Certain carved-out oil and natural gas properties (Classic
    Carve-Out) of Classic Hydrocarbons Holdings, L.P,
    (Classic) that will be acquired by the Partnership
    at the closing of the initial public offering. Classic was
    formed in 2006 to engage in the exploration, development,
    production, and sale of oil and natural gas primarily in East
    Texas. Prior to the Offering, Memorial Resource owned a 90.21%
    limited partner interest in Classic and an 83.33% membership
    interest in the general partner of Classic.  Note 2 
    Basis of
    Presentation and Significant Accounting Policies  (a)
    Basis
    of Presentation     F-23




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
  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.
  (b)
    Use of
    Estimates      (c)
    Principles
    of Consolidation    (d)
    Cash
    and Cash Equivalents    (e)
    Concentrations
    of Credit Risk     F-24




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
      (f)
    Oil
    and Natural Gas Properties    units-of-production
    (g)
    Oil
    and Gas Reserves  12-month
  units-of-production
 F-25




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
    2010-03 2010-03), Oil and Gas Reserve Estimations and Disclosures Extractive
    Activities  Oil and Gas Modernization of Oil and Gas Reporting Requirements
  12-month
  (h)
    Other
    Property and Equipment    (i)
    Impairments    property-by-property
 F-26




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
  (j)
    Asset
    Retirement Obligations  Asset Retirement and Environmental
    Obligations
  Asset retirement obligations at December 31, 2010

$
10,892Accretion expense


210Revision of estimates


(4)Asset retirement obligations at March 31, 2011

$
11,098   (k)
    Other
    Long-Term Assets    (l)
    Revenue
    Recognition    (m)
    General
    and Administrative Expense    (n)
    Derivative
    Instruments   F-27




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
      (o)
    Income
    Taxes      (p)
    Equity
    Compensation    (q)
    New
    Accounting Pronouncements  2010-20 2010-20 2010-20
  2010-14, Regulation S-X, Rule 4-10 Rule 33-8995. 2010-03 2010-14
  2010-06, 2010-06 2010-06
 F-28




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
    Note 3 
    Acquisitions
    and Divestitures          Oil and gas properties

$
15,397Prepaid assets


450Assumed liabilities


(1,728)Net purchase price

$
14,119              F-29




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
  Note 4 
    Fair
    Value Measurements of Financial Instruments    Level 1 
  Level 2  over-the-counter
  Level 3 
  Assets
    and Liabilities Measured at Fair Value on a Recurring
    Basis
    Derivative Instruments 
    Fair Value Measurements at March 31, 2011 UsingSignificantQuoted Prices in


Significant Other


UnobservableActive Markets


Observable Inputs


Inputs


Fair Value at(Level 1)


(Level 2)


(Level 3)


March 31, 2011Assets:Commodity derivative price swap contracts

$



$
2,589


$



$
2,589Commodity derivative price collar contracts






3,589







3,589Total assets

$



$
6,178


$



$
6,178 F-30




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
  Fair Value Measurements at March 31, 2011 UsingSignificantQuoted Prices in


Significant Other


UnobservableActive Markets


Observable Inputs


Inputs


Fair Value at(Level 1)


(Level 2)


(Level 3)


March 31, 2011Liabilities:Commodity derivative price swap contracts

$



$
(43)


$



$
(43)Commodity derivative price collar contracts






(1,155)







(1,155)Commodity derivative put option






(270)







(270)Commodity derivative interest rate swaps






(335)







(335)Total liabilities

$



$
(1,803)


$



$
(1,803)   Fair Value Measurements at December 31, 2010 UsingSignificantQuoted Prices in


Significant Other


Unobservable


Fair Value atActive Markets


Observable Inputs


Inputs


December 31,(Level 1)


(Level 2)


(Level 3)


2010Assets:Commodity derivative price swap contracts

$



$
3,067


$



$
3,067Commodity derivative price collar contracts






4,086







4,086Total assets

$



$
7,153


$



$
7,153Liabilities:Commodity derivative price collar contracts

$



$
(420)


$



$
(420)Commodity derivative put options






(58)







(58)Commodity derivative interest rate swaps






(403)







(403)Total liabilities

$



$
(881)


$



$
(881)     Assets
    and Liabilities Measured at Fair Value on a Nonrecurring
    Basis:
    Asset Retirement Obligations
    (AROs)
  Properties Acquired in Business
    Combinations
 F-31




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
    Note 5 
    Risk
    Management and Derivative Instruments      (a)
    Commodity
    Derivatives    Natural Gas SwapsAverage Monthly

Weighted AverageBeginning Month

Ending Month

Volumes (MMBtu)

Fixed Price1/1/2011



12/31/2011



88,000


$
6.112/1/2011



6/30/2011



54,000


$
4.101/1/2012



6/30/2012



15,000


$
5.351/1/2012



12/31/2012



90,000


$
5.811/1/2013



12/31/2013



61,000


$
5.76   Natural Gas CollarsAverage Monthly

Weighted Average

Weighted AverageBeginning Month

Ending Month

Volumes (MMBtu)

Floor Price

Ceiling Price1/1/2011

4/30/2011

6,000

$
6.25


$
7.251/1/2011

8/31/2011

6,000

$
6.25


$
7.151/1/2011

12/31/2011

193,000

$
5.28


$
6.757/1/2011

12/31/2011

21,000

$
4.00


$
5.001/1/2012

12/31/2012

275,000

$
4.88


$
6.191/1/2013

12/31/2013

349,000

$
4.76


$
5.79   F-32




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
  Natural Gas Put OptionsAverage MonthlyBeginning Month


Ending Month


Volumes (MMBtu)


Strike Price1/1/2011



12/31/2011



250,000


$
4.301/1/2012



12/31/2012



70,000


$
4.80   Oil CollarsAverage Monthly

Weighted Average

Weighted AverageBeginning Month

Ending Month

Volumes (Bbls)

Floor Price

Ceiling Price1/1/2011


12/31/2011

1,200

$
75.00


$
94.001/1/2012


12/31/2012

900

$
73.33


$
94.971/1/2013


6/30/2013

300

$
80.00


$
99.601/1/2013


12/31/2013

600

$
70.00


$
104.70   (b)
    Interest
    Rate Swaps  1-month
  3-month
    (c)
    Balance
    Sheet Presentation    March 31,


December 31,Type

Balance Sheet Location(1)

2011


2010Natural Gas Swaps

Short-term derivative instruments  Current assets

$
1,309


$
1,661Natural Gas Collars

Short-term derivative instruments  Current assets


2,124



2,459Natural Gas Swaps

Long-term derivative instruments  Long-term assets


1,279



1,406Natural Gas Collars

Long-term derivative instruments  Long-term assets


1,465



1,627Natural Gas Puts

Short-term derivative instruments  Current liabilities


(224)



(23)Natural Gas Collars

Short-term derivative instruments  Current liabilities


(167)



(56)Natural Gas Swaps

Short-term derivative instruments  Current liabilities


(43)



Oil Collars

Short-term derivative instruments  Current liabilities


(186)



(81)Interest Rate Swaps

Short-term derivative instruments  Current liabilities


(268)



(153)Natural Gas Puts

Long-term derivative instruments  Long-term
    liabilities


(45)



(35)Natural Gas Swaps

Long-term derivative instruments  Long-term
    liabilities






 F-33




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
  March 31,


December 31,Type

Balance Sheet Location(1)

2011


2010Natural Gas Collars

Long-term derivative instruments  Long-term
    liabilities


(527)



(174)Oil Collars

Long-term derivative instruments  Long-term
    liabilities


(275)



(109)Interest Rate Swaps

Long-term derivative instruments  Long-term
    liabilities


(67)



(250)Net derivative financial instruments

$
4,375


$
6,272     (1)
    
    The fair value of derivative instruments reported in the
    Predecessors combined balance sheets are subject to
    netting arrangements and qualify for net presentation. The
    following table reports the net derivative fair values as
    reported in the Predecessors combined balance sheets at
    March 31, 2011 and December 31, 2010:  March 31, 2011


December 31, 2010Combined balance sheet classification:Current derivative contracts:Assets

$
2,694


$
3,791Liabilities


(186)



(109)Net current

$
2,508


$
3,682Noncurrent derivative contracts:Assets

$
2,142


$
2,699Liabilities


(275)



(109)Net noncurrent

$
1,867


$
2,590   (d)
    Gains
    (Losses) on Derivatives    Statements ofOperations

Three Months EndedLocation

March 31, 2011


March 31, 2010Gain/(loss)onCommodity derivative contracts(1)

derivatives


(703)



6,636Interest rate swaps(2)

Interest expense


53



28     (1)
    
    Included in these amounts are net cash receipts of approximately
    $1,259 and $930 for the three months ended March 31, 2011
    and March 31, 2010, respectively.(2)
    
    Included in the amounts are net cash payments of approximately
    $118 and $26 for the three months ended March 31, 2011 and
    March 31, 2010, respectively.  Note 6 
    Long Term
    Debt  The
    BlueStone Credit Facility
   F-34




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
            The
    Classic Credit Facility
      Note 7 
    Partners
    Capital   F-35




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
        Note 8 
    Incentive
    Interests        Note 9 
    Related
    Party Transactions     F-36




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
  Note 10 
    Commitments
    and Contingencies  (a)
    Lease
    Agreements    (b)
    Litigation    (c)
    Noncompete
    Agreements    Note 11 
    Defined
    Contribution Plan    Note 12 
    Subsequent
    Events    nd
   F-37




---



##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM              F-38




---



##### Table of Contents



PREDECESSOR
  COMBINED BALANCE SHEETS AS OF
 DECEMBER
    31, 2010 AND 2009
  2010


2009(In thousands)ASSETSCurrent assets:Cash and cash equivalents

$
5,654


$
5,297Accounts receivable:Oil and natural gas sales


6,175



5,025Joint interest owners and other


3,848



2,362Short-term derivative instruments


3,791



3,086Prepaid expenses and other current assets


771



1,110Total current assets


20,239



16,880Property and equipment, at cost:Oil and natural gas properties, successful efforts method


314,975



187,217Other


2,553



2,137317,528



189,354Accumulated depreciation, depletion and impairment


(93,224)



(61,358)Oil and natural gas properties, net


224,304



127,996Long-term derivative instruments


2,699



814Other long-term assets


1,298



463Total assets

$
248,540


$
146,153LIABILITIES AND PARTNERS CAPITALCurrent liabilities:Accounts payable

$
8,482


$
3,442Revenues payable


3,564



3,140Accrued liabilities


3,874



654Current portion of long-term debt


69



24Short-term derivative instruments


109



13Asset retirement obligations


25



113Total current liabilities


16,123



7,386Long-term debt


115,359



61,760Deferred tax liabilities


225



Asset retirement obligations


10,867



3,693Long-term derivative instruments


109



288Other long-term liabilities


56



38Total liabilities


142,739



73,165Commitments and contingencies (Note 11)Partners capital


105,801



72,988Total liabilities and partners capital

$
248,540


$
146,153    F-39




---



##### Table of Contents



PREDECESSOR
  COMBINED STATEMENTS OF OPERATIONS
 DECEMBER
    31, 2010, 2009 AND 2008
  2010


2009


2008(In thousands)Revenues:Oil & natural gas sales

$
37,308


$
24,541


$
49,313Other income


1,433



319



622Total revenues


38,741



24,860



49,935Costs and expenses:Lease operating


13,974



11,207



8,843Exploration


39



2,690



374Production and advalorem taxes


2,112



1,464



3,127Depreciation, depletion and amortization


20,066



15,226



12,353Impairment of proved oil and natural gas properties


11,800



3,480



14,166General and administrative


6,116



4,811



3,835Accretion


663



320



224Gain on derivative instruments


(10,264)



(10,834)



(9,815)Gain on sale of properties


(1)



(7,851)



(7,395)Other, net


890



304



Total costs and expenses


45,395



20,817



25,712Operating (loss) income


(6,654)



4,043



24,223Interest expense


(4,438)



(2,937)



(3,138)Income (loss) before income taxes


(11,092)



1,106



21,085Income tax expense


(225)







Net (loss) income

$
(11,317)


$
1,106


$
21,085    F-40




---



##### Table of Contents



PREDECESSOR
  COMBINED
    STATEMENTS OF CHANGES IN PARTNERS CAPITAL
 DECEMBER
    31, 2010, 2009 AND 2008
  Total PartnersCapital(In thousands)Balance January 1, 2008

$
37,682Contributions from partners


Distributions to partners


(4,191)Net income


21,085Balance December 31, 2008


54,576Contributions from partners


17,306Distributions to partners


Net income


1,106Balance December 31, 2009


72,988Contributions from partners


44,130Distributions to partners


Net loss


(11,317)Balance December 31, 2010

$
105,801    F-41




---



##### Table of Contents



PREDECESSOR
  COMBINED STATEMENTS OF CASH FLOWS
 DECEMBER
    31, 2010, 2009 AND 2008
  2010


2009


2008(In thousands)Cash flows from operating activities:Net (loss) income

$
(11,317
)

$
1,106


$
21,085Adjustments to reconcile net (loss) income to net cash providedby operating activities:Depreciation, depletion, and amortization


20,066



15,226



12,353Impairment of proved oil and natural gas properties


11,800



3,480



14,166Unrealized (gain) loss on derivatives


(2,674
)


6,430



(9,975
)Deferred income tax expense


225







Amortization of loan origination fees


745



109



26Accretion


663



320



224Gain on sale of properties


(1
)


(7,851
)


(7,395
)Exploratory dry hole costs


39



2,690



374Changes in operating assets and liabilities:Accounts receivable


(2,637
)


6,522



(5,044
)Prepaid expenses and other assets


227



(729
)


(187
)Accounts payable


855



(12,597
)


8,546Revenue payable


423



(1,171
)


(494
)Accrued liabilities


1,771



(842
)


(969
)Other


103



(21
)


128Net cash provided by operating activities


20,288



12,672



32,838Cash flows from investing activities:Acquisition of oil and natural gas properties


(104,542
)


(17,455
)


(15,199
)Additions to oil and gas properties


(13,129
)


(19,034
)


(45,378
)Additions to other property and equipment


(416
)


(210
)


(388
)Proceeds from the sale of oil and gas properties


1,400



11,752



15,418Net cash used by investing activities


(116,687
)


(24,947
)


(45,547
)Cash flows from financing activities:Advances on revolving credit facility


115,106



11,948



24,570Payments on revolving credit facility


(61,600
)


(12,749
)


(8,750
)Contributed capital


44,130



17,306



Distribution to partners










(4,191
)Proceeds from borrowings of long-term debt


182







Repayment of borrowings of long-term debt


(44
)


(27
)


(10
)Loan origination fees


(1,018
)


(489
)


Net cash provided by financing activities

$
96,756


$
15,989


$
11,619Net increase (decrease) in cash


357



3,714



(1,090
)Cash and cash equivalents, beginning of year

$
5,297


$
1,583


$
2,673Cash and cash equivalents, end of year

$
5,654


$
5,297


$
1,583Supplemental cash flows:Cash paid for interest

$
4,309


$
2,677


$
2,087Noncash investing and financing activities:Purchase of fixed assets with note payable






117



Environmental remediation net liability recorded as part of
    Merit acquisition (see Note 3)


1,450







    F-42




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS
  Note 1 
    Organization  General
      
    BlueStone Natural Resources, LLC (BlueStone) is a
    Delaware limited liability company formed in January 2006 to
    engage in the acquisition, development, production and
    exploration and sale of oil and natural gas. BlueStone is a
    wholly owned subsidiary of BlueStone Natural Resources Holdings,
    LLC (Holdings), whose sole purpose is to provide
    financing for BlueStone. BlueStone owns oil and natural gas
    producing properties in Texas. Prior to the Offering, Memorial
    Resource owned an 89.45% interest in BlueStone and certain
    members of BlueStones management owned a 10.55% interest.
    Certain carved-out oil and natural gas properties (Classic
    Carve-Out) of Classic Hydrocarbons Holdings, L.P,
    (Classic) that will be acquired by the Partnership
    at the closing of the initial public offering. Classic was
    formed in 2006 to engage in the exploration, development,
    production, and sale of oil and natural gas primarily in East
    Texas. Prior to the Offering, Memorial Resource owned a 90.21%
    limited partner interest in Classic and an 83.33% membership
    interest in the general partner of Classic.    Note 2 
    Basis of
    Presentation and Significant Accounting Policies  (a)
    Basis
    of Presentation   F-43




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
      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
  (b)
    Use of
    Estimates      (c)
    Principles
    of Combination    (d)
    Cash
    and Cash Equivalents    (e)
    Concentrations
    of Credit Risk and Significant Customers   F-44




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
            (f)
    Oil
    and Natural Gas Properties    units-of-production
 F-45




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
      2010


2009


2008Balance, January 1

$
821


$
1,468


$
124Additions to capitalized exploratory well costs pending
    determination of proved reserves


2,013



821



1,468Reclassification to proved oil and natural gas properties based
    on the determination of proved reserves


(821
)






(124
)Capitalized exploratory well costs charged to expense






(1,468
)


Balance, December 31

$
2,013


$
821


$
1,468   (g)
    Oil
    and Gas Reserves  12-month
  units-of-production
  2010-03 2010-03), Oil and Gas Reserve Estimations and Disclosures Extractive
    Activities  Oil and Gas Modernization of Oil and Gas Reporting Requirements
   F-46




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
  12-month
  (h)
    Other
    Property and Equipment    (i)
    Impairments    property-by-property
  (j)
    Asset
    Retirement Obligations  Asset Retirement and Environmental
    Obligations
  (k)
    Other
    Long-Term Assets   F-47




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
  (l)
    Revenue
    Recognition    (m)
    General
    and Administrative Expense    (n)
    Derivative
    Instruments      (o)
    Income
    Taxes      (p)
    Equity
    Compensation   F-48




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
    (q)
    New
    Accounting Pronouncements  2010-20 2010-20 2010-20
  2010-14, Regulation S-X, Rule 4-10 Rule 33-8995. 2010-03 2010-14
  2010-06, 2010-06 2010-06
  Note 3 
    Acquisitions
    and Divestitures         F-49




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
  2010
    Acquisitions
          2010

2009Actual

Pro Forma

Actual

Pro Forma(In thousands)

(In thousands)Forest Oil Properties:Revenues

$
38,741


$
47,409


$
24,860


$
41,131Net (loss) income

$
(11,317
)

$
(5,506
)

$
1,106


$
11,631     Oil and gas properties

$
15,397Prepaid assets


450Assumed liabilities


(1,728
)Net purchase price

$
14,119      F-50




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
      2009
    Acquisitions
        2008
    Acquisitions
    Divestitures
    of non-core assets
         F-51




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
    Note 4 
    Fair
    Value Measurements of Financial Instruments    Level 1
  Level 2 over-the-counter
  Level 3
  Assets
    and Liabilities Measured at Fair Value on a Recurring
    Basis
    Derivative Instruments
   F-52




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
    Fair Value Measurements at December 31, 2010 UsingQuoted Prices in


Significant Other


Significant


Fair Value atActive Markets


Observable Inputs


Unobservable Inputs


December 31,(Level 1)


(Level 2)


(Level 3)


2010Assets:Commodity derivative price swap contracts

$



$
3,067


$



$
3,067Commodity derivative collar contracts






4,086







4,086Total assets

$



$
7,153


$



$
7,153Liabilities:Commodity derivative price collar contracts

$



$
(420
)

$



$
(420
)Commodity derivative put options






(58
)






(58
)Commodity derivative interest rate swaps






(403
)






(403
)Total liabilities

$



$
(881
)

$



$
(881
)   Fair Value Measurements at December 31, 2009 UsingQuoted Prices in


Significant Other


SignificantActive Markets


Observable Inputs


Unobservable Inputs


Fair Value at(Level 1)


(Level 2)


(Level 3)


December 31, 2009Assets:Commodity derivative price swap contracts

$



$
1,683


$



$
1,683Commodity derivative collar contracts






2,264







2,264Total assets

$



$
3,947


$



$
3,947Liabilities:Commodity derivative price swap contracts

$



$
(104
)

$



$
(104
)Commodity derivative price collar contracts






(137
)






(137
)Commodity derivative interest rate swaps






(107
)






(107
)Total liabilities

$



$
(348
)

$



$
(348
)    F-53




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
  Assets
    and Liabilities Measured at Fair Value on a Nonrecurring
    Basis:
    Asset Retirement Obligations
    (AROs)
  Properties Acquired in Business
    Combinations
  Note 5 
    Risk
    Management and Derivative Instruments      (a)
    Commodity
    Derivatives    Natural Gas SwapsAverage Monthly

Weighted AverageBeginning Month

Ending Month

Volumes (MMBtu)

Fixed Price1/1/2011



12/31/2011



88,000


$
6.112/1/2011



6/30/2011



54,000


$
4.101/1/2012



6/30/2012



15,000


$
5.351/1/2012



12/31/2012



90,000


$
5.811/1/2013



12/31/2013



61,000


$
5.76  F-54




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
  Natural Gas CollarsAverage Monthly

Weighted Average

Weighted AverageBeginning Month

Ending Month

Volumes (MMBtu)

Floor Price

Ceiling price1/1/2011



4/30/2011



6,000


$
6.25


$
7.251/1/2011



8/31/2011



6,000


$
6.25


$
7.151/1/2011



12/31/2011



193,000


$
5.28


$
6.757/1/2011



12/31/2011



21,000


$
4.00


$
5.001/1/2012



12/31/2012



275,000


$
4.88


$
6.191/1/2013



12/31/2013



269,000


$
4.82


$
5.80   Natural Gas Put OptionsAverage MonthlyBeginning Month


Ending Month


Volumes (MMBtu)


Strike Price1/1/2011



12/31/2011



250,000


$
4.301/1/2012



12/31/2012



70,000


$
4.80   Oil CollarsAverage Monthly

Weighted Average

Weighted AverageBeginning Month

Ending Month

Volumes (Bbls)

Floor Price

Ceiling Price1/1/2011



12/31/2011



1,200


$
75.00


$
94.001/1/2012



12/31/2012



900


$
73.33


$
94.971/1/2013



6/30/2013



300


$
80.00


$
99.601/1/2013



12/31/2013



600


$
70.00


$
104.70   (b)
    Interest
    Rate Swaps  1-month
  3-month
   F-55




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
  (c)
    Balance
    Sheet Presentation    December 31,Type

Balance Sheet Location(1)

2010


2009Natural Gas Swaps

Short-term derivative instruments  Current assets

$
1,661


$
1,311Natural Gas Collars

Short-term derivative instruments  Current assets


2,459



1,773Natural Gas Swaps

Long-term derivative instruments  Long-term assets


1,406



372Natural Gas Collars

Long-term derivative instruments  Long-term assets


1,627



491Natural Gas Puts

Short-term derivative instruments  Current liabilities


(23)



Natural Gas Collars

Short-term derivative instruments  Current liabilities


(56)



Oil Collars

Short-term derivative instruments  Current liabilities


(81)



(13)Interest Rate Swaps

Short-term derivative instruments  Current liabilities


(153)



Natural Gas Puts

Long-term derivative instruments  Long-term
    liabilities


(35)



Natural Gas Swaps

Long-term derivative instruments  Long-term
    liabilities






(104)Natural Gas Collars

Long-term derivative instruments  Long-term
    liabilities


(174)



(49)Oil Collars

Long-term derivative instruments  Long-term
    liabilities


(109)



(75)Interest Rate Swaps

Long-term derivative instruments  Long-term
    liabilities


(250)



(107)Net derivative financial instruments

$
6,272


$
3,599     (1)
    
    The fair value of derivative instruments reported in the
    Predecessors combined balance sheets are subject to
    netting arrangements and qualify for net presentation. The
    following table reports the net derivative fair values as
    reported in the Predecessors combined balance sheets at
    December 31, 2010 and 2009:  December 31,2010


2009Combined balance sheet classification:Current derivative contracts:Assets

$
3,791


$
3,086Liabilities


(109)



(13)Net current

$
3,682


$
3,073Noncurrent derivative contracts:Assets

$
2,699


$
814Liabilities


(109)



(288)Net noncurrent

$
2,590


$
526   (d)
    Gains
    (Losses) on Derivatives   F-56




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
    Statements of


Years Ended December 31,Operations Location


2010


2009


2008Commodity derivative contracts(1)


Gain on derivatives


$
10,264


$
10,834


$
9,815Interest rate swaps(2)


Interest expense



(576)



(165)



(482)     (1)
    
    Included in these amounts are net cash receipts of approximately
    $7,294 and $17,574 for the years ended December 31, 2010
    and 2009, respectively and net cash payments of $487 in 2008.(2)
    
    Included in the amounts are net cash payments of approximately
    $281, $475 and $153 for the years ended December 31, 2010,
    2009 and 2008, respectively.  Note 6 
    Asset
    Retirement Obligations        2010


2009


2008Asset retirement obligations at beginning of year

$
3,806


$
3,342


$
1,940Liabilities added from acquisitions or drilling


7,116



996



1,541Liabilities removed upon sale of wells


(19)



(124)



(593)Current year accretion expense


663



320



224Revision of estimates


(674)



(728)



230Asset retirement obligations at end of year

$
10,892


$
3,806


$
3,342   Note 7 
    Long Term
    Debt    The
    BlueStone Credit Facility
   F-57




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
          The
    Classic Credit Facility
      Note 8 
    Partners
    Capital     F-58




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
      Note 9 
    Incentive
    Interests        Note 10 
    Related
    Party Transactions    Note 11 
    Commitments
    and Contingencies  (e)
    Lease
    Agreements   F-59




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
  (f)
    Litigation    (g)
    Noncompete
    Agreements    Note 12 
    Defined
    Contribution Plan    Note 13 
    Subsequent
    Events    nd
   F-60




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
  Note 14 
    Supplemental
    Oil and Gas Information  (Unaudited)  Capitalized
    Costs Relating to Oil and Natural Gas Producing
    Activities
    December 31,2010


2009


2008(In thousands)Evaluated oil and natural gas properties(1)

$
299,589


$
181,773


$
157,613Unevaluated oil and natural gas properties


15,385



5,445



2,354Accumulated depletion, depreciation and amortization(1)


(92,814
)


(60,978
)


(42,379
)$
222,160


$
126,240


$
117,588     (1)
    
    Amounts do not include costs for our gas gathering systems and
    related support equipment.  Costs
    Incurred in Oil and Natural Gas Property Acquisition,
    Exploration and Development Activities
    Years Ended December 31,2010


2009


2008(In thousands)Property acquisition costs, proved

$
104,542


$
17,455


$
15,199Property acquisition costs, unproved










Exploration and extension well costs


6,287



6,808



16,726Development costs(1)


6,842



12,226



28,652Total costs

$
117,671


$
36,489


$
60,577     (1)
    
    Amounts do not include costs for our gas gathering systems and
    related support equipment.  Standardized
    Measure of Discounted Future Net Cash Flows Relating to Proved
    Oil and Natural Gas Reserves
  Extractive
    Activities  Oil and Gas,
    
    future costs and selling prices will probably differ from those
    required to be used in these calculations;
    due to future market conditions and governmental regulations,
    actual rates of production in future years may vary
    significantly from the rate of production assumed in the
    calculations;
    a 10% discount rate may not be reasonable as a measure of the
    relative risk inherent in realizing future net oil and natural
    gas revenues; and
    future net revenues may be subject to different rates of income
    taxation. F-61




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
   12-month
  Oil
    and Natural Gas Reserves
      12-month 12-month 12-month
 F-62




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
    Proved ReservesNatural GasLiquid


EquivalentOil (MBbls)


Gas (MMcf)


(MBbls)


(MMcfe)Proved reserves, December 31, 2007


1,527



25,878







35,038Extensions and discoveries


108



21,212







21,857Purchase of minerals in place


46



6,199







6,480Production


(55
)


(3,834
)






(4,165
)Sale of minerals in place


(694
)


(1,211
)






(5,372
)Revision of previous estimates


(98
)


9,955







9,365Proved reserves, December 31, 2008


834



58,199







63,203Extensions and discoveries


6



3,533







3,571Purchase of minerals in place


32



8,001







8,195Production


(94
)


(5,281
)






(5,847
)Sale of minerals in place


(90
)










(538
)Revision of previous estimates


51



(2,800
)






(2,495
)Proved reserves, December 31, 2009


739



61,652







66,089Extensions and discoveries


60



7,602



211



9,225Purchase of minerals in place


259



78,046







79,599Production


(47
)


(7,314
)


(33
)


(7,792
)Sale of minerals in place














Revision of previous estimates


5



11,190



271



12,850Proved reserves, December 31, 2010


1,016



151,176



449



159,971   Proved Developed ReservesNatural GasLiquids

EquivalentOil (MBbls)

Gas (MMcf)

(MBbls)

(MMcfe)December 31, 2010


904



123,529



206



130,195December 31, 2009


687



47,809







51,934December 31, 2008


769



43,291







47,905   Proved Undeveloped ReservesNatural GasLiquids

EquivalentOil (MBbls)

Gas (MMcf)

(MBbls)

(MMcfe)December 31, 2010


112



27,647



243



29,775December 31, 2009


52



13,843







14,155December 31, 2008


65



14,908







15,298    F-63




---



##### Table of Contents



PREDECESSOR
  NOTES TO
    COMBINED FINANCIAL STATEMENTS  (Continued)
    12-month first-day-of-the-month
      Years Ended December 31,2010


2009


2008(In thousands)Future cash inflows

$
780,477


$
295,659


$
399,168Future production costs


(291,486
)


(120,657
)


(136,118
)Future development costs


(68,046
)


(31,180
)


(31,280
)Future income tax expense(1)


(5,463
)


(2,070
)


(2,794
)Future net cash flows before 10% discount

$
415,482


$
141,752


$
228,97610% annual discount for estimated timing of cash flows


(231,667
)


(77,916
)


(125,090
)Standardized measure of discounted future net cash flows

$
183,815


$
63,836


$
103,886     (1)
    
    Represents future amounts owed associated with Texas margin tax.  Changes
    in Standardized Measure of Discounted Future Net Cash Flows
    Relating to Proved Oil and Natural Gas Reserves
    Years Ended December 31,2010


2009


2008(In thousands)Beginning of year

$
63,836


$
103,886


$
94,968Sale of oil and natural gas produced, net of production costs


(21,222
)


(11,870
)


(38,657
)Purchase of minerals in place


104,729



6,213



22,695Sales of minerals in place






(612
)


(19,819
)Extensions and discoveries


8,526



2,332



21,571Changes in income taxes, net


(1,506
)


319



(225
)Changes in prices and costs


14,198



(44,997
)


(10,679
)Previously estimated development costs incurred


2,228



5,828



8,258Net changes in future development costs


(4,947
)


1,253



(2,505
)Revisions of previous quantities


12,192



(4,118
)


15,614Accretion of discount


6,481



10,517



9,602Changes in production rates and other


(700
)


(4,915
)


3,063End of year

$
183,815


$
63,836


$
103,886  F-64




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##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM                F-65




---



##### Table of Contents



FOREST
    ACQUISITION FINANCIAL STATEMENTSSTATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES
    FOR THE YEARS ENDED DECEMBER 31, 2009 AND 2008
    AND SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED)
  Six Months Ended


Year Ended December 31,June 30, 2010


2009


2008(unaudited)(In thousands)Operating revenues

$
8,668


$
16,271


$
44,836Direct operating expenses:


2,857



5,746



8,009Revenues in excess of direct operating expenses

$
5,811


$
10,525


$
36,827    F-66




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##### Table of Contents



FOREST
    ACQUISITION FINANCIAL STATEMENTSNOTES TO THE STATEMENTS OF REVENUES AND DIRECT
    OPERATING EXPENSES FOR
    THE YEARS ENDED DECEMBER 31, 2009 AND 2008 AND
    SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED)
  Note 1.
    Basis of
    Presentation          Note 2.
    Significant
    Accounting Policies  Use of
    Estimates
    Revenue
    Recognition
    Direct
    Operating Expenses
    Note 3.
    Contingencies   F-67




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##### Table of Contents



FOREST
    ACQUISITION FINANCIAL STATEMENTS
    NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES FOR
    THE YEARS ENDED DECEMBER 31, 2009 AND 2008 AND
    SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED) 
    (CONTINUED)
  Note 4.
    Excluded
    Expenses      Note 5.
    Supplemental
    Information relating to oil and natural gas producing activities
     (unaudited)  Estimated
    Quantities of Proved Oil and Natural Gas Reserves
         F-68




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##### Table of Contents



FOREST
    ACQUISITION FINANCIAL STATEMENTS
    NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES FOR
    THE YEARS ENDED DECEMBER 31, 2009 AND 2008 AND
    SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED) 
    (CONTINUED)
    Proved Reserves(1)EquivalentOil (MBbls)

Gas (MMcf)

(MMcfe)Proved reserves, December 31, 2007


176



61,050



62,103Extensions and discoveries


1



613



621Purchase of minerals in place










Production


(15
)


(5,152
)


(5,243
)Sale of minerals in place










Revision of previous estimates


(4
)


(761
)


(785
)Proved reserves, December 31, 2008


158



55,750



56,696Extensions and discoveries






532



533Purchase of minerals in place






Production


(12
)


(4,347
)


(4,417
)Sale of minerals in place






Revision of previous estimates


(11
)


(3,863
)


(3,926
)Proved reserves, December 31, 2009


135



48,072



48,886     (1)
    
    Proved reserves information is identical to proved developed
    reserves information, as all proved reserves are also developed.  first-day-of-the-month
    Standardized
    Measure of Discounted Future Net Cash Flows Relating to Oil and
    Gas Reserves
  Extractive Activities  Oil and Gas
 F-69




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##### Table of Contents



FOREST
    ACQUISITION FINANCIAL STATEMENTS
    NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES FOR
    THE YEARS ENDED DECEMBER 31, 2009 AND 2008 AND
    SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED) 
    (CONTINUED)
    Standardized
    Measure of Discounted Future Net Cash Flows Relating to Oil and
    Gas Reserves
    
    future costs and selling prices will probably differ from those
    required to be used in these calculations;
    due to future market conditions and governmental regulations,
    actual rates of production in future years may vary
    significantly from the rate of production assumed in the
    calculations;
    a 10% discount rate may not be reasonable as a measure of the
    relative risk inherent in realizing future net oil and natural
    revenues; and
    the effects of federal income taxes have been excluded    Years Ended December 31,2009


2008(In thousands)Future cash inflows

$
194,467


$
327,588Future production costs


(86,297
)


(122,126
)Future development costs






Future income tax expense(1)


(1,361
)


(2,293
)Future net cash flows before 10% discount

$
106,809


$
203,16910% annual discount for estimated timing of cash flows


(48,663
)


(98,675
)Standardized measure of discounted future net cash flows

$
58,146


$
104,494     (1)
    
    Represents future amounts owed associated with Texas margin tax. F-70




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##### Table of Contents



FOREST
    ACQUISITION FINANCIAL STATEMENTS
    NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES FOR
    THE YEARS ENDED DECEMBER 31, 2009 AND 2008 AND
    SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED) 
    (CONTINUED)
   Changes
    in Standardized Measure of Discounted Future Net Cash Flows
    Relating to Proved Oil and Natural Gas Reserves
    Years Ended December 31,2009


2008(In thousands)Beginning of year

$
104,494


$
143,713Sale of oil and natural gas produced, net of production costs


(10,525
)


(36,827
)Purchase of minerals in place






Sales of minerals in place






Extensions and discoveries


1,314



1,679Changes in income taxes, net


410



331Changes in prices and costs


(40,554
)


(16,934
)Previously estimated development costs incurred






Net changes in future development costs






Revisions of previous quantities


(7,312
)


(1,834
)Accretion of discount


10,560



14,515Changes in production rates and other


(241
)


(149
)End of year

$
58,146


$
104,494  F-71




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##### Table of Contents



REPORT OF
    INDEPENDENT AUDITORS  
      Form S-1,
    
   F-72




---



##### Table of Contents



BLUESTONE
    NATURAL RESOURCES, LLCS ACQUISITION OF
    CERTAIN BP AMERICA PRODUCTION COMPANY PROPERTIES
 STATEMENTS
    OF REVENUES AND DIRECT OPERATING EXPENSES Three Months EndedMarch 31,


For Years Ended December 31,2011


2010


2010


2009


2008(Unaudited)(In thousands)Operating revenues

$
3,732


$
6,482


$
18,896


$
18,972


$
45,538Direct operating expenses


1,572



2,280



7,003



6,535



9,016Revenues in excess of direct operating expenses

$
2,160


$
4,202


$
11,893


$
12,437


$
36,522    F-73




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##### Table of Contents



BLUESTONE
    NATURAL RESOURCES, LLCS ACQUISITION OF
    CERTAIN BP AMERICA PRODUCTION COMPANY PROPERTIESNOTES TO THE STATEMENTS OF REVENUES AND
    DIRECT OPERATING EXPENSES
    FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
    AND FOR THE THREE MONTHS ENDED MARCH 31, 2011 AND 2010
    (UNAUDITED)
  Note 1:
    Basis of
    Presentation            Note 2:
    Significant
    Account Policies  Use of
    Estimates
    Revenue
    Recognition
    Direct
    Operating Expenses
   F-74




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##### Table of Contents



BLUESTONE
    NATURAL RESOURCES, LLCS ACQUISITION OF
    CERTAIN BP AMERICA PRODUCTION COMPANY PROPERTIES
    NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING
    EXPENSES
    FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
    AND FOR THE THREE MONTHS ENDED MARCH 31, 2011 AND 2010
    (UNAUDITED)  (Continued)
  Note 3:
    Commitment
    and Contingencies    Note 4:
    Excluded
    Expenses      Note 5:
    Sales to
    Affiliates    Note 6:  Capital
    Expenditures (unaudited)
    Note 7:
    Subsequent
    Events   F-75




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##### Table of Contents



Supplemental
    Oil and Gas Information (unaudited)
    12-month first-day-of-the-month
    Natural Gas


Crude(MMcf)


Oil (MBbls)


Total (MMcfe)Quantities of proved reserves:Balance December 31, 2007


63,953



89



64,487Revisions(1)


(709
)


(1
)


(715
)Extensions


25







25Production


(5,890
)


(8
)


(5,938
)Balance December 31, 2008


57,379



80



57,859Revisions(1)


(3,124
)


(4
)


(3,148
)Extensions


533







533Production


(5,405
)


(7
)


(5,447
)Balance December 31, 2009


49,383



69



49,797Revisions(1)


2,089



5



2,119Production


(4,787
)


(9
)


(4,841
)Balance December 31, 2010


46,685



65



47,075     (1)
    
    Revisions include only the impact of changes in product prices.  Natural Gas

Crude(MMcf)

Oil (MBbls)

Total (MMcfe)Proved developed reserves:December 31, 2007


63,953



89



64,487December 31, 2008


57,379



80



57,859December 31, 2009


49,383



69



49,797December 31, 2010


46,685



65



47,075  F-76




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##### Table of Contents



2010


2009


2008Future cash inflows

$
201,777


$
187,622


$
317,502Future production and development costsProduction


(85,159
)


(81,653
)


(115,267
)Development










Future income taxes


(1,412
)


(1,313
)


(2,223
)Future net cash flows


115,206



104,656



200,01210% annual discount for estimated timing of cash flows


(57,867
)


(51,252
)


(103,334
)Standardized measure of discounted future net cash flows

$
57,339


$
53,404


$
96,678   12-month
  Petroleum Product

2010


2009


2008Natural Gas per Mcf

$
4.22


$
3.72


$
5.48Crude Oil per Bbl

$
73.17


$
56.28


$
40.89     2010


2009


2008Standardized measure of discounted future net cash flow,
    beginning of year

$
53,404


$
96,678


$
134,649Changes from:Sales of natural gas, crude oil and natural gas liquids
    produced, net of production costs


(12,583
)


(11,439
)


(37,994
)Extensions






1,314



80Net changes in prices and production costs


10,285



(40,132
)


(13,821
)Revisions of previous quantity estimates


2,610



(5,313
)


(1,508
)Net change in taxes


(35
)


379



320Accretion of discount


5,402



9,767



13,596Change in timing and other


(1,744
)


2,150



1,356Aggregate change in standardized measure of discounted future
    net cash flows


3,935



(43,274
)


(37,971
)Standardized measure of discounted future net cash flow, end of
    year

$
57,339


$
53,404


$
96,678  F-77




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##### Table of Contents



APPENDIX A



First
    Amended and Restated Agreement of Limited Partnership of
    Memorial Production Partners LP


A-1




---



##### Table of Contents



APPENDIX B



Glossary
    of Terms



The following includes a description of the meanings of some of
    the oil and natural gas industry terms used in this prospectus.



Analogous Reservoir:  Analogous
    reservoirs, as used in resource assessments, have similar rock
    and fluid properties, reservoir conditions (depth, temperature,
    and pressure) and drive mechanisms, but are typically at a more
    advanced stage of development than the reservoir of interest and
    thus may provide concepts to assist in the interpretation of
    more limited data and estimation of recovery. When used to
    support proved reserves, analogous reservoir refers to a
    reservoir that shares all of the following characteristics with
    the reservoir of interest: (i) the same geological
    formation (but not necessarily in pressure communication with
    the reservoir of interest); (ii) the same environment of
    deposition; (iii) similar geologic structure; and
    (iv) the same drive mechanism.



API Gravity:  A system of classifying
    oil based on its specific gravity, whereby the greater the
    gravity, the lighter the oil.



Basin:  A large depression on the
    earths surface in which sediments accumulate.



Bbl:  One stock tank barrel, or 42
    U.S. gallons liquid volume, used in reference to oil or
    other liquid hydrocarbons.



Bbl/d:  One Bbl per day.



Bcf:  One billion cubic feet of natural
    gas.



Bcfe:  One billion cubic feet of natural
    gas equivalent.



Boe:  One barrel of oil equivalent,
    calculated by converting natural gas to oil equivalent barrels
    at a ratio of six Mcf of natural gas to one Bbl of oil.



Boe/d:  One Boe per day.



Btu:  One British thermal unit, the
    quantity of heat required to raise the temperature of a
    one-pound mass of water by one degree Fahrenheit.



Deterministic Estimate:  The method of
    estimating reserves or resources is called deterministic when a
    single value for each parameter (from the geoscience,
    engineering or economic data) in the reserves calculation is
    used in the reserves estimation procedure.



Development Project:  A development
    project is the means by which petroleum resources are brought to
    the status of economically producible. As examples, the
    development of a single reservoir or field, an incremental
    development in a producing field or the integrated development
    of a group of several fields and associated facilities with a
    common ownership may constitute a development project.



Developed Acreage:  The number of acres
    which are allocated or assignable to producing wells or wells
    capable of production.



Development Well:  A well drilled within
    the proved area of an oil or natural gas reservoir to the depth
    of a stratigraphic horizon known to be productive.



Differential:  An adjustment to the
    price of oil or natural gas from an established spot market
    price to reflect differences in the quality
    and/or
    location of oil or natural gas.



Dry Hole Or Dry Well:  A well found to
    be incapable of producing hydrocarbons in sufficient quantities
    such that proceeds from the sale of such production would exceed
    production expenses and taxes.



Economically Producible:  The term
    economically producible, as it relates to a resource, means a
    resource which generates revenue that exceeds, or is reasonably
    expected to exceed, the costs of the operation.



B-1




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##### Table of Contents



Estimated Ultimate Recovery:
  Exploitation:
  Exploratory Well:
  Field: and/or
  Gross Acres Gross
    Wells:
  MBbl:
  MBbls/d:
  MBoe:
  MBoe/d:
  MBtu:
  MBtu/d:
  Mcf:
  Mcf/d:
  MMBtu:
  MMcf:
  MMcfe:
  Net Acres Net
    Wells:
  Net Production:
  Net Revenue Interest:
  NGLs:
  NYMEX:
  Oil:
  Operator: and/or
  Play:
  Probabilistic Estimate:
 B-2




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##### Table of Contents



Productive Well:
  Proved Developed Reserves:
  Proved Reserve Additions:
  Proved Reserves: first-day-of-the-month
  Proved Undeveloped Reserves:
  Realized Price:
  Recompletion:
  Reliable Technology:
 B-3




---



##### Table of Contents



Reserves:
  Reserve Life:
  Reservoir: and/or
  Resources:
  Spacing: 40-acre
  Spot Price:
  Standardized Measure:
  Undeveloped Acreage:
  Wellbore:
  Working Interest:
  Workover:
  WTI:
   B-4




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##### Table of Contents



APPENDIX C



Netherland,
    Sewell & Associates, Inc. Summary of December 31,
    2010 Reserves



(NSAI LOGO)



June 17,
    2011



Mr. Doug
    Redmond

BlueStone Natural Resources

2100 South Utica, Suite 200

Tulsa, Oklahoma 74114



Dear Mr. Redmond:



In accordance with your request, we have estimated the proved
    reserves and future revenue, as of December 31, 2010, to
    the BlueStone Natural Resources (BlueStone) interest in certain
    oil and gas properties located in Texas. As requested, the
    BlueStone working and net revenue interests shown in this report
    include the interests being acquired from BP America Production
    Company. It is our understanding that this acquisition had an
    effective date of January 1, 2011, and closed on
    May 31, 2011. We completed our evaluation on May 23,
    2011. It is our understanding that the proved reserves estimated
    in this report constitute approximately 96 percent of all
    proved reserves owned by BlueStone. The estimates in this report
    have been prepared in accordance with the definitions and
    guidelines of the U.S. Securities and Exchange Commission
    (SEC) and, with the exception of the exclusion of future income
    taxes, conform to the FASB Accounting Standards Codification
    Topic 932, Extractive Activities  Oil and Gas.
    Definitions are presented immediately following this letter. As
    specified by BlueStone, all of these proved reserves will be
    contributed to Memorial Production Partners LP (Memorial) at the
    closing of its anticipated Master Limited Partnership initial
    public offering. This report has been prepared for
    BlueStones use in the upcoming Master Limited Partnership
    transaction; in our opinion, the assumptions, data, methods, and
    procedures used in the preparation of this report are
    appropriate for such purpose.



We estimate the net reserves and future net revenue to the
    BlueStone interest in these properties, as of December 31,
    2010, to be: Net Reserves


Future Net Revenue ($)Oil


Gas





Present WorthCategory

(Barrels)


(MCF)


Total


at 10%Proved Developed Producing


243,205



106,668,195



250,009,600



139,071,100Proved Developed Non-Producing


180,410



40,003,477



101,986,500



41,119,900Proved Undeveloped


62,635



22,571,840



42,361,800



8,975,200Total Proved


486,251



169,243,516



394,357,800



189,166,200   Totals may not add because of rounding.
     4500
    Thanksgiving
    Tower1601 Elm
    Street  Dallas, Texas
    75201-4754
    nsai@nsai-petro.com Ph. 214-969-5401
     Fax:
    214-969-5411
  1221
    Lamar Street, Suite1200
    Houston,
    Texas77010-3072
    netherlandsewell.com Ph. 713-654-4950
    fax: 713-654-4951
 C-1




---



##### Table of Contents



12-month first-day-of-the-month
       C-2




---



##### Table of Contents



NETHERLAND, SEWELL & ASSOCIATES, INC.
   By:
    /s/  C.H.
    (Scott) Rees III     By: /s/  Richard
    B. Talley, Jr.Richard
    B. Talley, Jr., P.E. 102425
    Vice President

By: /s/  David
    E. NiceDavid
    E. Nice, P.G. 346
    Vice PresidentDate Signed: June 17, 2011

Date Signed: June 17, 2011      Please be advised that the digital
    document you are viewing is provided by Netherland,
    Sewell & Associates, Inc. (NSAI) as a convenience to
    our clients. The digital document is intended to be
    substantively the same as the original signed document
    maintained by NSAI. The digital document is subject to the
    parameters, limitations, and conditions stated in the original
    document. In the event of any differences between the digital
    document and the original document, the original document shall
    control and supersede the digital document.
 C-3




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##### Table of Contents



DEFINITIONS
    OF OIL AND GAS RESERVES Adapted
    from U.S. Securities and Exchange Commission
    Regulation S-X
    Section 210.4-10(a)
   Regulation S-X Section 210.4-10(a).
  Acquisition of properties.
  Analogous reservoir.
  (i)
    Same geological formation (but not necessarily in pressure
    communication with the reservoir of interest);  (ii)
    Same environment of deposition;  (iii)
    Similar geological structure; and  (iv)
    Same drive mechanism.  Instruction to paragraph (a)(2):
  Bitumen.
  Condensate.
  Deterministic estimate.
  Developed oil and gas
    reserves.
  (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.    C-4




---



##### Table of Contents



DEFINITIONS
    OF OIL AND GAS RESERVES Adapted
    from U.S. Securities and Exchange Commission
    Regulation S-X
    Section 210.4-10(a)
     Supplemental definitions from the 2007 Petroleum Resources
    Management System:  Developed Producing Reserves  Developed Producing
    Reserves are expected to be recovered from completion intervals
    that are open and producing at the time of the estimate.
    Improved recovery reserves are considered producing only after
    the improved recovery project is in operation.
  Developed Non-Producing Reserves  Developed
    Non-Producing Reserves include shut-in and behind-pipe Reserves.
    Shut-in Reserves are expected to be recovered from
    (1) completion intervals which are open at the time of the
    estimate but which have not yet started producing,
    (2) wells which were shut-in for market conditions or
    pipeline connections, or (3) wells not capable of
    production for mechanical reasons. Behind-pipe Reserves are
    expected to be recovered from zones in existing wells which will
    require additional completion work or future recompletion prior
    to start of production. In all cases, production can be
    initiated or restored with relatively low expenditure compared
    to the cost of drilling a new well.
  Development costs.
  (i)
    Gain access to and prepare well locations for drilling,
    including surveying well locations for the purpose of
    determining specific development drilling sites, clearing
    ground, draining, road building, and relocating public roads,
    gas lines, and power lines, to the extent necessary in
    developing the proved reserves.  (ii)
    Drill and equip development wells, development-type
    stratigraphic test wells, and service wells, including the costs
    of platforms and of well equipment such as casing, tubing,
    pumping equipment, and the wellhead assembly.  (iii)
    Acquire, construct, and install production facilities such as
    lease flow lines, separators, treaters, heaters, manifolds,
    measuring devices, and production storage tanks, natural gas
    cycling and processing plants, and central utility and waste
    disposal systems.  (iv)
    Provide improved recovery systems.  Development project.
  Development well.
  Economically producible.
  Estimated ultimate recovery
    (EUR).
    C-5




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##### Table of Contents



DEFINITIONS
    OF OIL AND GAS RESERVES Adapted
    from U.S. Securities and Exchange Commission
    Regulation S-X
    Section 210.4-10(a)
   Exploration costs.
  (i)
    Costs of topographical, geographical and geophysical studies,
    rights of access to properties to conduct those studies, and
    salaries and other expenses of geologists, geophysical crews,
    and others conducting those studies. Collectively, these are
    sometimes referred to as geological and geophysical or
    G&G costs.  (ii)
    Costs of carrying and retaining undeveloped properties, such as
    delay rentals, ad valorem taxes on properties, legal costs for
    title defense, and the maintenance of land and lease records.  (iii)
    Dry hole contributions and bottom hole contributions.  (iv)
    Costs of drilling and equipping exploratory wells.  (v)
    Costs of drilling exploratory-type stratigraphic test wells.  Exploratory well.
  Extension well.
  Field. and/or
  Oil and gas producing activities.
  (i)
    Oil and gas producing activities include:  (A)
    The search for crude oil, including condensate and natural gas
    liquids, or natural gas (oil and gas) in their
    natural states and original locations;(B)
    The acquisition of property rights or properties for the purpose
    of further exploration or for the purpose of removing the oil or
    gas from such properties;(C)
    The construction, drilling, and production activities necessary
    to retrieve oil and gas from their natural reservoirs, including
    the acquisition, construction, installation, and maintenance of
    field gathering and storage systems, such as:  (1)
    Lifting the oil and gas to the surface; and    C-6




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##### Table of Contents



DEFINITIONS
    OF OIL AND GAS RESERVES Adapted
    from U.S. Securities and Exchange Commission
    Regulation S-X
    Section 210.4-10(a)
   (2)
    Gathering, treating, and field processing (as in the case of
    processing gas to extract liquid hydrocarbons); and  (D)
    Extraction of saleable hydrocarbons, in the solid, liquid, or
    gaseous state, from oil sands, shale, coalbeds, or other
    nonrenewable natural resources which are intended to be upgraded
    into synthetic oil or gas, and activities undertaken with a view
    to such extraction.  Instruction 1 to paragraph
    (a)(16)(i):
  a.
    The first point at which oil, gas, or gas liquids, natural or
    synthetic, are delivered to a main pipeline, a common carrier, a
    refinery, or a marine terminal; andb.
    In the case of natural resources that are intended to be
    upgraded into synthetic oil or gas, if those natural resources
    are delivered to a purchaser prior to upgrading, the first point
    at which the natural resources are delivered to a main pipeline,
    a common carrier, a refinery, a marine terminal, or a facility
    which upgrades such natural resources into synthetic oil or gas.  Instruction 2 to paragraph
    (a)(16)(i):
  (ii)
    Oil and gas producing activities do not include:  (A)
    Transporting, refining, or marketing oil and gas;(B)
    Processing of produced oil, gas, or natural resources that can
    be upgraded into synthetic oil or gas by a registrant that does
    not have the legal right to produce or a revenue interest in
    such production;(C)
    Activities relating to the production of natural resources other
    than oil, gas, or natural resources from which synthetic oil and
    gas can be extracted; or(D)
    Production of geothermal steam.  Possible 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.    C-7




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##### Table of Contents



DEFINITIONS
    OF OIL AND GAS RESERVES Adapted
    from U.S. Securities and Exchange Commission
    Regulation S-X
    Section 210.4-10(a)
    (iv)
    The proved plus probable and proved plus probable plus possible
    reserves estimates must be based on reasonable alternative
    technical and commercial interpretations within the reservoir or
    subject project that are clearly documented, including
    comparisons to results in successful similar projects.  (v)
    Possible reserves may be assigned where geoscience and
    engineering data identify directly adjacent portions of a
    reservoir within the same accumulation that may be separated
    from proved areas by faults with displacement less than
    formation thickness or other geological discontinuities and that
    have not been penetrated by a wellbore, and the registrant
    believes that such adjacent portions are in communication with
    the known (proved) reservoir. Possible reserves may be assigned
    to areas that are structurally higher or lower than the proved
    area if these areas are in communication with the proved
    reservoir.  (vi)
    Pursuant to paragraph (a)(22)(iii) of this section, where direct
    observation has defined a highest known oil (HKO) elevation and
    the potential exists for an associated gas cap, proved oil
    reserves should be assigned in the structurally higher portions
    of the reservoir above the HKO only if the higher contact can be
    established with reasonable certainty through reliable
    technology. Portions of the reservoir that do not meet this
    reasonable certainty criterion may be assigned as probable and
    possible oil or gas based on reservoir fluid properties and
    pressure gradient interpretations.  Probable reserves.
  (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 (a)(17)(iv) and (a)(17)(vi) of
    this section.  Probabilistic estimate.
  Production costs.
  (i)
    Costs incurred to operate and maintain wells and related
    equipment and facilities, including depreciation and applicable
    operating costs of support equipment and facilities and other
    costs of    C-8




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DEFINITIONS
    OF OIL AND GAS RESERVES Adapted
    from U.S. Securities and Exchange Commission
    Regulation S-X
    Section 210.4-10(a)
   operating and maintaining those wells and related equipment and
    facilities. They become part of the cost of oil and gas
    produced. Examples of production costs (sometimes called lifting
    costs) are:  (A)
    Costs of labor to operate the wells and related equipment and
    facilities.(B)
    Repairs and maintenance.(C)
    Materials, supplies, and fuel consumed and supplies utilized in
    operating the wells and related equipment and facilities.(D)
    Property taxes and insurance applicable to proved properties and
    wells and related equipment and facilities.  (E)
    Severance taxes.  (ii)
    Some support equipment or facilities may serve two or more oil
    and gas producing activities and may also serve transportation,
    refining, and marketing activities. To the extent that the
    support equipment and facilities are used in oil and gas
    producing activities, their depreciation and applicable
    operating costs become exploration, development or production
    costs, as appropriate. Depreciation, depletion, and amortization
    of capitalized acquisition, exploration, and development costs
    are not production costs but also become part of the cost of oil
    and gas produced along with production (lifting) costs
    identified above.  Proved area.
  Proved oil and gas reserves.
  (i)
    The area of the 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.    C-9




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DEFINITIONS
    OF OIL AND GAS RESERVES Adapted
    from U.S. Securities and Exchange Commission
    Regulation S-X
    Section 210.4-10(a)
    (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.  Proved properties.
  Reasonable certainty.
  Reliable technology.
  Reserves.
  Note to paragraph (a)(26):
    C-10




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DEFINITIONS
    OF OIL AND GAS RESERVES Adapted
    from U.S. Securities and Exchange Commission
    Regulation S-X
    Section 210.4-10(a)
    Excerpted from the FASB Accounting Standards Codification
    Topic 932, Extractive Activities  Oil and Gas:
  932-235-50-30
    A standardized measure of discounted future net cash flows
    relating to an entitys interests in both of the following
    shall be disclosed as of the end of the year:
  a.
    Proved oil and gas reserves (see
    paragraphs 932-235-50-3
    through
    50-11B)  b.
    Oil and gas subject to purchase under long-term supply,
    purchase, or similar agreements and contracts in which the
    entity participates in the operation of the properties on which
    the oil or gas is located or otherwise serves as the producer of
    those reserves (see
    paragraph 932-235-50-7).  The standardized measure of discounted future net cash flows
    relating to those two types of interests in reserves may be
    combined for reporting purposes.
  932-235-50-31
    All of the following information shall be disclosed in the
    aggregate and for each geographic area for which reserve
    quantities are disclosed in accordance with
    paragraphs 932-235-50-3
    through
    50-11B:
  a.
    Future cash inflows. These shall be computed by applying
    prices used in estimating the entitys proved oil and gas
    reserves to the year-end quantities of those reserves. Future
    price changes shall be considered only to the extent provided by
    contractual arrangements in existence at year-end.  b.
    Future development and production costs. These costs shall be
    computed by estimating the expenditures to be incurred in
    developing and producing the proved oil and gas reserves at the
    end of the year, based on year-end costs and assuming
    continuation of existing economic conditions. If estimated
    development expenditures are significant, they shall be
    presented separately from estimated production costs.c.
    Future income tax expenses. These expenses shall be computed
    by applying the appropriate year-end statutory tax rates, with
    consideration of future tax rates already legislated, to the
    future pretax net cash flows relating to the entitys
    proved oil and gas reserves, less the tax basis of the
    properties involved. The future income tax expenses shall give
    effect to tax deductions and tax credits and allowances relating
    to the entitys proved oil and gas reserves.  d.
    Future net cash flows. These amounts are the result of
    subtracting future development and production costs and future
    income tax expenses from future cash inflows.  e.
    Discount. This amount shall be derived from using a discount
    rate of 10 percent a year to reflect the timing of the
    future net cash flows relating to proved oil and gas
    reserves.  f.
    Standardized measure of discounted future net cash flows.
    This amount is the future net cash flows less the computed
    discount.
  Reservoir. and/or
  Resources.
    C-11




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DEFINITIONS
    OF OIL AND GAS RESERVES Adapted
    from U.S. Securities and Exchange Commission
    Regulation S-X
    Section 210.4-10(a)
   Service well.
  Stratigraphic test well.
  Undeveloped oil and gas
    reserves.
  (i)
    Reserves on undrilled acreage shall be limited to those directly
    offsetting development spacing areas that are reasonably certain
    of production when drilled, unless evidence using reliable
    technology exists that establishes reasonable certainty of
    economic producibility at greater distances.  (ii)
    Undrilled locations can be classified as having undeveloped
    reserves only if a development plan has been adopted indicating
    that they are scheduled to be drilled within five years, unless
    the specific circumstances, justify a longer time.   From the SECs Compliance and Disclosure Interpretations
    (October 26, 2009):
  Although several types of projects  such as
    constructing offshore platforms and development in urban areas,
    remote locations or environmentally sensitive
    locations  by their nature customarily take a longer
    time to develop and therefore often do justify longer time
    periods, this determination must always take into consideration
    all of the facts and circumstances. No particular type of
    project per se justifies a longer time period, and any extension
    beyond five years should be the exception, and not the rule.
  Factors that a company should consider in determining whether
    or not circumstances justify recognizing reserves even though
    development may extend past five years include, but are not
    limited to, the following:
  
    The companys level of ongoing significant development
    activities in the area to be developed (for example, drilling
    only the minimum number of wells necessary to maintain the lease
    generally would not constitute significant development
    activities);
    The companys historical record at completing
    development of comparable long-term projects;
    The amount of time in which the company has maintained the
    leases, or booked the reserves, without significant development
    activities;
    The extent to which the company has followed a previously
    adopted development plan (for example, if a company has changed
    its development plan several times without taking significant
    steps to implement any of those plans, recognizing proved
    undeveloped reserves typically would not be
    appropriate); and
    The extent to which delays in development are caused by
    external factors related to the physical operating environment
    (for example, restrictions on development on Federal lands, but
    not
 C-12




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DEFINITIONS
    OF OIL AND GAS RESERVES Adapted
    from U.S. Securities and Exchange Commission
    Regulation S-X
    Section 210.4-10(a)
   obtaining government permits), rather than by internal
    factors (for example, shifting resources to develop properties
    with higher priority).
  (iii)
    Under no circumstances shall estimates for undeveloped reserves
    be attributable to any acreage for which an application of fluid
    injection or other improved recovery technique is contemplated,
    unless such techniques have been proved effective by actual
    projects in the same reservoir or an analogous reservoir, as
    defined in paragraph (a)(2) of this section, or by other
    evidence using reliable technology establishing reasonable
    certainty.      C-13




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##### Table of Contents



APPENDIX D



Netherland,
    Sewell & Associates, Inc. Summary Reserve Report



(NSAI LOGO)



June 17, 2011



Mr. Jay Graham

WHT Energy Partners LLC

950 Echo Lane, Suite 200

Houston, Texas 77024



Dear Mr. Graham:



In accordance with your request, we have audited the estimates
    prepared by WHT Energy Partners LLC (WHT), as of
    December 31, 2010, of the proved reserves and future
    revenue to the WHT interest in certain oil and gas properties
    located in De Soto Parish, Louisiana, and Panola and Rusk
    Counties, Texas. This report was prepared for use by WHT in an
    upcoming Master Limited Partnership (MLP) transaction. This
    audit includes all of the properties owned by WHT but only the
    40 percent interest that will be conveyed to the MLP. The
    100 percent interest owned by WHT was audited in our report
    dated June 2, 2011. With the exception of this interest
    change, we completed our evaluation on or about June 2,
    2011. We have examined the estimates with respect to reserves
    quantities, reserves categorization, future producing rates,
    future net revenue, and the present value of such future net
    revenue, using the definitions set forth in U.S. Securities
    and Exchange Commission (SEC)
    Regulation S-X
    Rule 4-10(a).
    The estimates of reserves and future revenue have been prepared
    in accordance with the definitions and guidelines of the SEC
    and, with the exception of the exclusion of future income taxes,
    conform to the FASB Accounting Standards Codification Topic 932,
    Extractive Activities  Oil and Gas. This report has
    been prepared for WHTs use in filing with the SEC; in our
    opinion the assumptions, data, methods, and procedures used in
    the preparation of this report are appropriate for such purpose.



The following table sets forth WHTs estimates of the net
    reserves and future net revenue, as of December 31, 2010,
    for the audited properties: Net Reserves





Future Net Revenue (M$)Oil


NGL


Gas





Present WorthCategory

(MBBL)


(MBBL)


(MMCF)


Total


at 10%Proved Developed Producing


692.8



2,884.9



55,189.7



257,764.5



103,028.9Proved Developed Behind-Pipe


67.0



0.0



3,735.2



13,274.9



7,476.1Proved Undeveloped


177.4



1,167.4



23,681.5



72,101.6



11,800.8Total Proved


937.2



4,052.3



82,606.3



343,141.0



122,305.7   Totals may not add because of rounding.
     4500
    Thanksgiving
    Tower1601 Elm
    Street  Dallas,
    Texas75201-4754
    nsai@nsai-petro.com Ph. 214-969-5401
     Fax:
    214-969-5411
  1221
    Lamar Street, Suite1200
    Houston,
    Texas77010-3072
    
    netherlandsewell.com Ph. 713-654-4950
    fax: 713-654-4951
 D-1




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##### Table of Contents



lease-by-lease
     12-month first-day-of-the-month
       D-2




---



##### Table of Contents



NETHERLAND, SEWELL & ASSOCIATES,
    INC.
  By:
    /s/  C.H.
    (Scott) Rees III, P.E.     By:
    /s/  Justin
    S. Hamilton, P.E. 104999       D-3




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##### Table of Contents



APPENDIX E



Miller
    and Lents, Ltd. Summary of January 1, 2011
    Reserves



(MILLER AND LENTS, LTD.)



May 24,
    2011



Mr. Donald P. Gann, Jr.

COO/Managing Partner

Classic Hydrocarbons Holdings, LP

One Ridgmar Centre

6500 West Freeway, Suite 222

Fort Worth, TX 76116 Re:

Reserves, Resources, and
    Future Net Revenues
    As of January 1, 2011       Net Reserves


Future Net RevenuesDiscounted atLiquids,


Gas,


Undiscounted,


10% Per Year,Reserves Category

MBbls.


MMcf


M$


M$Proved Developed Producing


738.8



29,156.5



107,926.3



45,616.6Proved Developed Nonproducing


2.2



963.9



1,476.9



468.8Proved Undeveloped


286.8



3,705.8



20,566.4



6,602.9Total Proved Reserves


1,027.8



33,826.2



129,669.6



52,688.3   Definitions
     Two
    Houston Center    909 Fannin Street,
    Suite 1300    Houston, Texas
    77010
 Telephone
    713-651-9455    Telefax
    713-654-9914  e-mail:
    mail@millerandlents.com
 E-1




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##### Table of Contents



Mr. Donald
    P. Gann, Jr.
    May 24, 2011 Classic
    Hydrocarbons Holdings, LP
    Page 2  Regulation S-X, Rule 4-10(a)
    Economic
    Considerations
  first-day-of-the-month 12-month per-unit
  Attachments
      Other
    Considerations
   E-2




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##### Table of Contents



Mr. Donald
    P. Gann, Jr.
    May 24, 2011 Classic
    Hydrocarbons Holdings, LP
    Page 3               E-3




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##### Table of Contents



Mr. Donald
    P. Gann, Jr.
    May 24, 2011 Classic
    Hydrocarbons Holdings, LP
    Page 4       No. F-1442
  
  E-4




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##### Table of Contents



Common Units
 Representing Limited Partner
    Interests
  Memorial Production Partners
    LP
  
    PRELIMINARY PROSPECTUS
 ,
    2011
    Citi
    Raymond James
    Wells Fargo Securities
    J.P. Morgan




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##### Table of Contents



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

$
33,379FINRA filing fee


29,250Stock exchange listing fee


*Underwriter structuring fee


*Printing and engraving expenses


*Accounting fees and expenses


*Legal fees and expenses


*Transfer agent and registrar fees


*Miscellaneous


*Total

$
*     *
    
    To be provided by amendment.  Item 14.
    Indemnification
    of Directors and Officers.  Section 17-108
        Item 15.
    Recent
    Sales of Unregistered Securities.   II-1




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##### Table of Contents



Item 16.
    Exhibits
    and Financial Statement Schedules.    ExhibitNumber



Description1
.1*



Form of Underwriting Agreement3
.1



Certificate of Limited Partnership of Memorial Production
    Partners LP3
.2



Agreement of Limited Partnership of Memorial Production Partners
    LP3
.3*



Form of First Amended and Restated Agreement of Limited
    Partnership of Memorial Production Partners LP (included as
    Appendix A to the prospectus)3
.4



Certificate of Formation of Memorial Production Partners GP LLC3
.5



Limited Liability Company Agreement of Memorial Production
    Partners GP LLC3
.6*



Form of Amended and Restated Limited Liability Company Agreement
    of Memorial Production Partners GP LLC5
.1*



Opinion of Akin Gump Strauss Hauer & Feld LLP as to
    the legality of the securities being registered8
.1*



Opinion of Akin Gump Strauss Hauer & Feld LLP relating
    to tax matters10
.1*



Form of Credit Agreement10
.2*



Form of Contribution, Conveyance and Assumption Agreement10
.3*



Form of Long-Term Incentive Plan10
.4*



Form of Omnibus Agreement21
.1



List of Subsidiaries of Memorial Production Partners LP23
.1



Consent of KPMG LLP23
.2



Consent of KPMG LLP23
.3



Consent of Ernst & Young LLP23
.4



Consent of Netherland, Sewell & Associates, Inc.23
.5



Consent of Miller and Lents, Ltd.23
.6*



Consent of Akin Gump Strauss Hauer & Feld LLP
    (contained in Exhibit 5.1)23
.7*



Consent of Akin Gump Strauss Hauer & Feld LLP
    (contained in Exhibit 8.1)24
.1



Powers of Attorney (included on the signature page to this
    registration statement)99
.1



Netherland, Sewell & Associates, Inc. Summary of
    December 31, 2010 Reserves (included as Appendix C to
    the prospectus)99
.2



Netherland, Sewell & Associates, Inc. Summary Reserve
    Report (included as Appendix D to the prospectus)99
.3



Miller and Lents, Ltd. Summary of January 1, 2011 Reserves
    (included as Appendix E to the prospectus)     *
    
    To be filed by amendment.  Item 17.
    Undertakings.     II-2




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##### Table of Contents



II-3




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##### Table of Contents



SIGNATURES
      By:
    Memorial Production Partners GP LLC, its general partnerBy:
    /s/  John
    A. Weinzierl          Signature

Title

Date/s/  John
    A. WeinzierlJohn
    A. Weinzierl

President, Chief Executive Officer and Chairman
    (Principal Executive Officer)

June 23, 2011/s/  Andrew
    J. CozbyAndrew
    J. Cozby

Vice President, Finance
    (Principal Financial Officer)

June 23, 2011/s/  Patrick
    T. NguyenPatrick
    T. Nguyen

Chief Accounting Officer
    (Principal Accounting Officer)

June 23, 2011/s/  Kenneth
    A. HershKenneth
    A. Hersh

Director

June 23, 2011  II-4




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##### Table of Contents



EXHIBIT INDEX
  ExhibitNumber



Description1
.1*



Form of Underwriting Agreement3
.1



Certificate of Limited Partnership of Memorial Production
    Partners LP3
.2



Agreement of Limited Partnership of Memorial Production Partners
    LP3
.3*



Form of First Amended and Restated Agreement of Limited
    Partnership of Memorial Production Partners LP (included as
    Appendix A to the prospectus)3
.4



Certificate of Formation of Memorial Production Partners GP LLC3
.5



Limited Liability Company Agreement of Memorial Production
    Partners GP LLC3
.6*



Form of Amended and Restated Limited Liability Company Agreement
    of Memorial Production Partners GP LLC5
.1*



Opinion of Akin Gump Strauss Hauer & Feld LLP as to
    the legality of the securities being registered8
.1*



Opinion of Akin Gump Strauss Hauer & Feld LLP relating
    to tax matters10
.1*



Form of Credit Agreement10
.2*



Form of Contribution, Conveyance and Assumption Agreement10
.3*



Form of Long-Term Incentive Plan10
.4*



Form of Omnibus Agreement21
.1



List of Subsidiaries of Memorial Production Partners LP23
.1



Consent of KPMG LLP23
.2



Consent of KPMG LLP23
.3



Consent of Ernst & Young LLP23
.4



Consent of Netherland, Sewell & Associates, Inc.23
.5



Consent of Miller and Lents, Ltd.23
.6*



Consent of Akin Gump Strauss Hauer & Feld LLP
    (contained in Exhibit 5.1)23
.7*



Consent of Akin Gump Strauss Hauer & Feld LLP
    (contained in Exhibit 8.1)24
.1



Powers of Attorney (included on the signature page to this
    registration statement)99
.1



Netherland, Sewell & Associates, Inc. Summary of
    December 31, 2010 Reserves (included as Appendix C to
    the prospectus)99
.2



Netherland, Sewell & Associates, Inc. Summary Reserve
    Report (included as Appendix D to the prospectus)99
.3



Miller and Lents, Ltd. Summary of January 1, 2011 Reserves
    (included as Appendix E to the prospectus)     *
    
    To be filed by amendment.