S-1/A 1 h82870a4sv1za.htm FORM S-1/A sv1za
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As filed with the Securities and Exchange Commission on November 9, 2011
 
Registration No. 333-175090
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Amendment No. 4
to
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:  As soon as practicable after this Registration Statement becomes effective.
 
If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  o
 
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer o Accelerated filer o Non-accelerated filer þ Smaller reporting company o
(Do not check if a smaller reporting company)
 
 
The 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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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 NOVEMBER 9, 2011
 
PRELIMINARY PROSPECTUS
 
(MEMORIAL PRODUCTION PARTNERS LP LOGO)
Memorial Production Partners LP
10,000,000 Common Units
Representing Limited Partner Interests
 
 
 
 
We are a Delaware limited partnership formed in April 2011 by Memorial Resource Development LLC to own and acquire oil and natural gas properties in North America. This is the initial public offering of our common units. No public market currently exists for our common units. We currently estimate that the initial public offering price per common unit will be between $19.00 and $21.00 per common unit. We have applied to list our common units on the NASDAQ Global Market under the symbol “MEMP.”
 
 
Investing in our common units involves risks. Please read “Risk Factors” beginning on page 24.
 
These risks include the following:
 
  •  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 and its affiliates.
 
  •  We would not have generated sufficient available cash on a pro forma basis to have paid the minimum quarterly distribution on all of our units for the twelve months ended September 30, 2011.
 
  •  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 will 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.
 
  •  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 $6.68 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   Total
 
Public offering price
  $             $          
Underwriting discount(1)
  $       $    
Proceeds, before expenses, to Memorial Production Partners LP
  $       $  
 
 
(1) Excludes a structuring fee equal to 0.25% of the gross proceeds of this offering payable to Citigroup Global Markets Inc.
 
To the extent that the underwriters sell more than 10,000,000 common units in this offering, the underwriters have the option to purchase up to an additional 1,500,000 common units on the same terms and conditions as set forth above.
 
The underwriters expect to deliver the common units on or about          , 2011.
 
 
 
 
         
Citigroup   Raymond James      Wells Fargo Securities
 
Barclays Capital J.P. Morgan RBC Capital Markets
 
 
 
 
Sanders Morris Harris
 
 
 
 
          , 2011


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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.
 
Through and including          , 2011 (25 days after the date of this prospectus), all dealers that effect transactions in our common units, whether or not participating in this offering, may be required to deliver a prospectus. This delivery is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to their unsold allotments or subscriptions.
 
This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Forward-Looking Statements.”


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Industry and Market Data
 
The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Although we believe these third-party sources are reliable and that the information is accurate and complete, we have not independently verified the information.
 
Commonly Used Defined Terms
 
As used in this prospectus, unless we indicate otherwise, the following terms have the following meanings:
 
  •  “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 and its wholly-owned subsidiaries, (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., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, 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 (including the contribution to us of Columbus Energy, LLC, a wholly-owned subsidiary of BlueStone Natural Resources Holdings, LLC, and ETX I LLC, a wholly-owned subsidiary of WHT Energy Partners LLC, each of which owns certain of the Partnership Properties) at the closing of this offering, in each case including transactions related thereto, which are described on page 8; 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.


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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 24 and the historical and pro forma financial statements and the notes to those financial statements. The information presented in this prospectus assumes (i) an initial public offering price of $20.00 per common unit (the midpoint of the price range set forth on the cover of this prospectus) and (ii) unless otherwise indicated, that the underwriters do not exercise their option to purchase additional common units.
 
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 October 1, 2010, as applicable, in the case of pro forma financial income statement or operating data, and on December 31, 2010 or September 30, 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
 
We are a Delaware limited partnership formed in April 2011 by Memorial Resource to own and acquire oil and natural gas properties in North America. Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions. We believe our properties are well suited for our partnership because they consist of mature onshore oil and natural gas reservoirs with long-lived, predictable production profiles and modest capital requirements. As of December 31, 2010, our total estimated proved reserves were approximately 325 Bcfe, of which approximately 81% were classified as proved developed reserves including approximately 14% classified as proved developed non-producing. Based on our pro forma average net production for the year ended December 31, 2010 of 52 MMcfe/d, our total estimated proved reserves had a reserve-to-production ratio of 17 years. Based on our pro forma proved reserves volumes at December 31, 2010, we or Memorial Resource operate 94% of the properties in which we have interests, and we own an average working interest of 43% across our oil and natural gas properties.
 
We believe our business relationship with Memorial Resource, which owns our general partner and will own approximately 37.7% of our outstanding common units and all of our subordinated units, will enhance our ability to maintain or grow our production and expand our proved reserves base over time. Memorial Resource is a Delaware limited liability company formed by Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which we refer to as the Funds, to own, acquire, exploit and develop oil and natural gas properties and to own our general partner. As part of the formation transactions, the Funds will contribute to Memorial Resource their respective ownership of five separate portfolio companies (including our predecessor), all of which are engaged in the business of owning, acquiring, exploiting, and developing oil and natural gas properties, and certain of which will contribute the Partnership Properties to us. Memorial Resource will engage in its business with the objective of growing its


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reserves, production and cash flows, as well as owning our general partner and a significant limited partner interest in us.
 
Our Properties
 
Our properties are located in South and East Texas and consist of mature, legacy onshore oil and natural gas reservoirs. We believe our properties are well suited for our partnership because they have predictable production profiles, low decline rates, long reserve lives and modest capital requirements. The Partnership Properties consist of operated working interests in producing and undeveloped leasehold acreage and in identified producing wells in South and East Texas, and non-operated working interests in producing and undeveloped leasehold acreage. As of December 31, 2010, we owned 133,309 gross (112,828 net) acres of developed properties and 14,374 gross (6,146 net) acres of undeveloped properties, all held by production, with 345 proved low-risk infill drilling, recompletion and development opportunities in our core operational areas. As of December 31, 2010, we had interests in 1,290 gross (609 net) producing wells across our properties, with an average working interest of 47%. Based on our forecasted daily production which is reflected in our reserve reports, the average estimated decline rate for our existing proved developed producing reserves is approximately 9% for the twelve months ending December 31, 2011, approximately 9% compounded average annual decline for the subsequent four years and approximately 8% per year thereafter. As of December 31, 2010, approximately 60 Bcfe, or 19%, of our estimated proved reserves were classified as proved undeveloped, of which approximately 83% were natural gas. Based on the production estimates and pricing assumptions included in our reserve reports, we believe that through 2015, our low-risk development inventory will provide us with the opportunity to maintain our targeted average net production of 49 MMcfe/d without acquiring incremental reserves.
 
The following table summarizes pro forma information by producing region regarding our estimated oil and natural gas reserves as of December 31, 2010 and our average net production for the year ended December 31, 2010. The reserve estimates attributable to the Partnership Properties are derived from our reserve reports.
 
                                                                 
    Estimated Pro Forma
  Average Net Pro
  Average
       
    Net Proved Reserves   Forma Production   Reserve-to-
  Producing
        % Natural
  % Proved
          Production
  Wells
    Bcfe   Gas   Developed   MMcfe/d   %   Ratio(1)   Gross   Net
                        (Years)        
 
South Texas
    172.2       98 %     87 %     32       61 %     15       563       424  
East Texas
    152.5       76 %     76 %     20       39 %     21       727       185  
                                                                 
Total
    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
 
We expect to adopt a hedging policy designed to reduce the impact to our cash flows from commodity price volatility. Under this policy, we intend to enter into 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 of time. We may, however, from time to time hedge more or less than this approximate range. Memorial Resource will contribute to us at the closing of this offering derivative contracts for the three months ending December 31, 2011 and the years ending December 31, 2012, 2013, 2014, and 2015 covering approximately 77%, 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.
 
Our commodity derivative contracts may consist of natural gas, oil and NGL financial swaps, put options and/or collar contracts and natural gas basis financial swaps. By removing a significant portion of price volatility associated with production, we believe we will mitigate, but not eliminate, the potential negative


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effects of reductions in commodity prices on our cash flow from operations for those periods. However, our hedging activity may also reduce our ability to benefit from increases in commodity prices. Additionally, we intend to individually identify these non-speculative hedges as “designated hedges” for U.S. federal income tax purposes as we enter into them. For a description of our commodity derivative contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — Commodity Derivative Contracts.”
 
Our Principal Business Relationships
 
We view our relationships with Memorial Resource, Natural Gas Partners and the Funds as significant competitive strengths. We believe these relationships will provide us with potential acquisition opportunities from a portfolio of additional oil and natural gas properties that meet our acquisition criteria, as well as access to personnel with extensive technical expertise and industry relationships.
 
Our Relationship with Memorial Resource
 
Following the completion of this offering, Memorial Resource will be our largest unitholder, holding 6,061,294 common units (approximately 37.7% of all outstanding) and 5,360,912 subordinated units (100% of all outstanding), and will own all of the voting interests in our general partner and 50% of the economic interest in our incentive distribution rights. 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. We believe that many of these properties are (or after additional capital is invested will become) suitable for us, based on our criteria that suitable properties consist of mature onshore oil and natural gas reservoirs with long-lived, low-decline, predictable production profiles. We also believe the largely contiguous and overlapping nature of Memorial Resource’s and our East Texas acreage, along with joint ownership in specific properties, will provide key operational, logistical and technical benefits derived from our aligned interests and information sharing among personnel, in addition to various economic benefits.
 
The following table summarizes pro forma information by producing region regarding Memorial Resource’s estimated oil and natural gas reserves as of December 31, 2010 and its average net production for the year ended December 31, 2010.
 
                                                                 
    Estimated Pro Forma
                Average
             
    Net Proved Reserves(1)     Average Net Pro
    Reserve-to-
    Producing
 
                % Proved
    Forma Production     Production
    Wells  
    Bcfe     % Natural Gas     Developed     MMcfe/d     %     Ratio(2)     Gross     Net  
                                  (Years)              
 
East Texas(3)
    760.6       84%       30%         43       64%         48       1,067       306  
North Louisiana
    224.7       73%       44%       18       27%       35       267       172  
Rockies
    51.0       67%       41%       6       9%       25       123       85  
                                                                 
Total
    1,036.3       81%       34%       67       100%       43       1,457       563  
                                                                 
 
 
(1) Memorial Resource’s estimated pro forma net proved reserves are (i) based primarily on reserve reports prepared by third-party independent petroleum engineers and (ii) exclusive of our estimated pro forma net proved reserves.
 
(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 properties in which we have a joint interest. Memorial Resource’s portion of these properties included 169 Bcfe of reserves as of December 31, 2010 and 20 MMcfe/d of average net pro forma production for the year ended December 31, 2010 associated with properties acquired by WHT Energy


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Partners LLC in April 2011. Please read “— Our Partnership Structure and Formation Transactions — Background Information Regarding Our Predecessor and the Partnership Properties.”
 
As a result of its significant ownership interests in us and our general partner, we believe Memorial Resource will be motivated to support the successful execution of our business strategy and will provide us with opportunities to pursue acquisitions that will be accretive to our unitholders. Memorial Resource views our partnership as part of its growth strategy, and we believe that Memorial Resource will be incentivized to contribute or sell additional assets to us and to pursue acquisitions jointly with us in the future. However, Memorial Resource will regularly evaluate acquisitions and dispositions and may elect to acquire or dispose of properties in the future without offering us the opportunity to participate in those transactions. Moreover, after this offering, Memorial Resource will continue to be free to act in a manner that is beneficial to its interests without regard to ours, which may include electing not to present us with future acquisition opportunities. Although we believe Memorial Resource will be incentivized to offer properties to us for purchase, none of Memorial Resource, the Funds or any of their affiliates will have any obligation to sell or offer properties to us following the consummation of this offering. If Memorial Resource fails to present us with, or successfully competes against us for, acquisition opportunities, then our ability to replace or increase our estimated proved reserves may be impaired, which would adversely affect our cash flow from operations and our ability to make cash distributions to our unitholders. Please read “Conflicts of Interest and Fiduciary Duties.”
 
Memorial Resource will also provide management, administrative, and operations personnel to us and our general partner under an omnibus agreement that it will enter into with us and our general partner at the completion of this offering. Under this agreement, we will utilize Memorial Resource’s staff of 49 engineers and geologists and 106 management and administrative personnel as of November 1, 2011, who collectively have an average of 23 years of experience operating properties in our areas of operations. Please read “Management” for more information about the management of our partnership and our use of Memorial Resource personnel, and “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement” for more information about the omnibus agreement.
 
Our Relationship with Natural Gas Partners and the Funds
 
Founded in 1988, Natural Gas Partners, or NGP, is a family of private equity investment funds with aggregate committed capital of over $7 billion, organized to make direct equity investments in the energy industry. NGP is part of the investment platform of NGP Energy Capital Management, one of the leading investment franchises in the natural resources sector with over $9 billion in aggregate committed capital under management. The employees of NGP are experienced energy professionals with substantial expertise in investing in the oil and natural gas business. In connection with NGP’s business, these employees review a large number of potential acquisitions and are involved in decisions relating to the acquisition and disposition of oil and natural gas assets by the various portfolio companies in which NGP owns interests. We believe that our relationship with NGP, and its experience investing in oil and natural gas companies, provides us with a number of benefits, including increased exposure to acquisition opportunities and access to a significant group of transactional and financial professionals who have experience in assisting the companies in which it has invested to meet their financial and strategic growth objectives. Although we may have the opportunity to make acquisitions as a result of our relationship with NGP, NGP has no legal obligation to offer to us (or inform us about) any acquisition opportunities, may decide not to offer any acquisition opportunities to us and is not restricted from competing with us, and we cannot say which, if any, of such potential acquisition opportunities we would choose to pursue.
 
The Funds, which are three of the private equity funds managed by NGP, collectively own 100% of Memorial Resource. The Funds also will collectively directly own, through non-voting membership interests in our general partner, 50% of the economic interest in our incentive distribution rights. The remaining economic interest in our incentive distribution rights is owned by Memorial Resource. Given this alignment of interests between NGP, the Funds, Memorial Resource and us, we believe we will benefit from the collective expertise of NGP’s employees and their extensive network of industry relationships, and accordingly the access to potential acquisition opportunities that might not otherwise be available to us.


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Our Business Strategies
 
Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions. To achieve our objective, we intend to execute the following 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;
 
  •  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.
 
For a more detailed description of our business strategies, please read “Business and Properties — Our Business Strategies.”
 
Our Competitive Strengths
 
We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our objective of generating and growing cash available for distribution:
 
  •  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.
 
For a more detailed discussion of our competitive strengths, please read “Business and Properties — Our Competitive Strengths.”


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Risk Factors
 
An investment in our common units involves risks. Below is a summary of certain key risk factors that you should consider in evaluating an investment in our common units. This list is not exhaustive. Please read the full discussion of these risks and other risks described under “Risk Factors” beginning on page 24.
 
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.
 
  •  We would not have generated sufficient available cash on a pro forma basis to have paid the minimum quarterly distribution on all of our units for the twelve months ended September 30, 2011.
 
  •  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 will 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 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.
 
  •  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.
 
  •  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.
 
  •  Control of our general partner and its incentive distribution rights may be transferred to a third party without unitholder consent.
 
  •  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.


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  •  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.


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Our Partnership Structure and Formation Transactions
 
We are a Delaware limited partnership formed by Memorial Resource to own and acquire oil and natural gas properties. In connection with this offering, the following transactions, which we refer to as the formation transactions, will occur:
 
Prior to the closing of this offering:
 
  •  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
 
At the closing of this offering:
 
  •  Memorial Resource will cause certain of its subsidiaries, including our predecessor, to contribute to us (i) a 100% membership interest in Columbus Energy, LLC, which owns certain oil and natural gas properties, (ii) a 100% membership interest in ETX I LLC, which owns certain oil and natural gas properties, (iii) specified oil and natural gas properties, which we refer to collectively with the properties owned by Columbus Energy, LLC and ETX I LLC as the “Partnership Properties,” and (iv) commodity derivative contracts for the three months ending December 31, 2011 and the years ending December 31, 2012, 2013, 2014, and 2015, which, together with the commodity derivative contracts to which Columbus Energy, LLC and ETX I LLC are party, cover approximately 77%, 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 6,061,294 common units and 5,360,912 subordinated units, representing an aggregate 53.3% limited partner interest in us;
 
  •  We will issue to our general partner 21,444 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 $0.54625 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 $177 million from the issuance and sale of 10,000,000 common units to the public (based on the midpoint of the price range set forth on the cover page of this prospectus), representing a 46.6% 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 $1.0 billion revolving credit facility, and we will use the proceeds as described in “Use of Proceeds”; 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.
 
If the underwriters exercise their option to purchase additional common units, we will use the net proceeds to reduce indebtedness incurred under our new revolving credit facility. If the underwriters exercise in full their option to purchase additional common units, the ownership interest of the public unitholders will increase to 11,500,000 common units, representing an aggregate 50.1% limited partner interest in us, the ownership interest of our general partner will increase to 22,945 general partner units, representing a 0.1% general partner interest in us, and the ownership interest of Memorial Resource will remain at 6,061,294 common units and 5,360,912 subordinated units, representing an aggregate 49.8% limited partner interest in us.


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Background Information Regarding Our Predecessor and the Partnership Properties
 
The Partnership Properties consist of properties and interests that will be contributed to us by our predecessor (which consists of the combined financial data of (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 (WHT), each a subsidiary of Memorial Resource). The properties being contributed to us by our predecessor include (1) certain of the properties acquired by our predecessor from Forest Oil Corporation (Forest Oil) in June 2010 (with respect to which certain financial statements are included elsewhere in this prospectus), (2) properties acquired by our predecessor from BP America Production Company (BP) in May 2011 (with respect to which certain financial statements are included elsewhere in this prospectus) and (3) a 40% undivided interest in the properties acquired by WHT in April 2011 (with respect to which certain financial statements are included elsewhere in this prospectus).


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Our Ownership and Organizational Structure
 
The table and diagram below illustrates our ownership and organizational structure based on total units outstanding after giving effect to this offering and the related formation transactions and assumes that the underwriters do not exercise their option to purchase additional common units.
 
                 
          Ownership
 
    Units     Interest  
 
Common units held by the public
    10,000,000       46.6 %
Common units held by Memorial Resource
    6,061,294       28.3 %
Subordinated units held by Memorial Resource
    5,360,912       25.0 %
General partner units
    21,444       0.1 %
                 
Total
    21,443,650       100.0 %
                 
 
(FLOW CHART)


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Principal Executive Offices and Internet Address
 
Our principal executive offices are located at 1401 McKinney, Suite 1025, Houston, Texas 77010, and our phone number is (713) 579-5700. Our website address is www.memorialpp.com and will be activated in connection with the closing of this offering. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.
 
Management of the Partnership
 
We are managed and operated by the board of directors and executive officers of Memorial Production Partners GP LLC, our general partner. Upon the completion of this offering, the board of directors of our general partner will have five members. At least one of our independent directors will be appointed prior to the date our common units are listed for trading on the NASDAQ Global Market, or NASDAQ. Memorial Resource will appoint our second and third independent directors within 90 days and one year, respectively, of such date. Memorial Resource owns all of the voting membership interests in our general partner and has the sole right to appoint its entire board of directors. Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or the board of directors of our general partner. Some of the executive officers and/or directors of our general partner currently serve as executive officers and/or directors of Memorial Resource, and some of the directors of our general partner currently serve in executive or other capacities for the Funds and their affiliates, including NGP. For more information about the directors and officers of our general partner, please read “Management — Directors and Executive Officers.”
 
Neither we nor our subsidiaries will have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether through directly hiring employees or by obtaining the services of personnel employed by Memorial Resource or others. We will reimburse our general partner and its affiliates for all expenses they incur or payments they make on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.
 
Prior to the closing of this offering, we and our general partner will enter into an omnibus agreement with Memorial Resource pursuant to which, among other things, Memorial Resource will provide management, administrative and operating services for us and our general partner. Memorial Resource will not be liable to us for its performance of, or failure to perform, services under this agreement unless there has been a final decision determining that Memorial Resource 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 unlawful. Our general partner will determine the expenses (including general and administrative expenses) to be reimbursed by us in accordance with our partnership agreement. We currently expect those general and administrative expenses (including those to be allocated to us by Memorial Resource) to be approximately $5.0 million for the twelve months ending December 31, 2012. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement.”
 
As is common with publicly traded partnerships and in order to maintain operational flexibility, we will conduct our operations through subsidiaries. We will initially have one direct subsidiary, Memorial Production Operating LLC, a Delaware limited liability company that will conduct business itself and through any subsidiaries that it may form or acquire. Memorial Production Operating LLC will initially have two direct subsidiaries, Columbus Energy, LLC and ETX I LLC, each a Delaware limited liability company.
 
Summary of Conflicts of Interest and Fiduciary Duties
 
Our general partner has a legal duty to manage us in a manner beneficial to the holders of our common and subordinated units. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, the officers and directors of our general partner also have a fiduciary duty to manage the business of our general partner in a manner beneficial to its owner, which is Memorial


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Resource. The officers and directors of Memorial Resource, in turn, have a fiduciary duty to manage Memorial Resource’s business in a manner beneficial to its owners, which are the Funds. Memorial Resource, the Funds, and their respective affiliates (including NGP) each manage, own, and hold assets and investments in other entities that compete or may compete with us. Additionally, certain of our general partner’s executive officers and directors will continue to have economic interests, investments and other economic incentives in affiliates of the Funds. As a result of these relationships, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its owners and affiliates, on the other hand. For example, our general partner is entitled to make determinations that affect our ability to generate the cash flows necessary to make cash distributions to our unitholders, including determinations related to:
 
  •  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.
 
These determinations will have an effect on the amount of cash distributions we make to the holders of our units, which in turn has an effect on whether our general partner receives incentive cash distributions. For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Risk Factors — Risks Inherent in an Investment in Us” and “Conflicts of Interest and Fiduciary Duties.”
 
Delaware law provides that Delaware limited partnerships may, in their partnership agreements, restrict or expand the fiduciary duties owed by the general partner to the limited partners and the partnership. Our partnership agreement limits the liability of our general partner and reduces the fiduciary duties it owes to holders of our common and subordinated units. Our partnership agreement also restricts the remedies available to holders of our common units for actions that might otherwise constitute a breach of the fiduciary duties that our general partner owes to our unitholders. By purchasing a common unit, unitholders agree to be bound by the terms of our partnership agreement and, pursuant to the terms of our partnership agreement, are treated as having consented to various actions contemplated in our partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties” for a description of the fiduciary duties imposed on our general partner by Delaware law, the material modifications of these duties contained in our partnership agreement and certain legal rights and remedies available to our unitholders.
 
Additionally, neither our partnership agreement nor the omnibus agreement contains any restrictions on the ability of Memorial Resource, the Funds, or any of their respective affiliates (including NGP and its affiliates’ portfolio investments) to compete with us. None of Memorial Resource, the Funds or any of their respective affiliates (including NGP) is under any obligation to offer properties or refer acquisitions or other opportunities to us.


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The Offering
 
Common units offered hereby 10,000,000 common units or 11,500,000 common units if the underwriters exercise in full their option to purchase additional common units.
 
Units outstanding after this offering 16,061,294 common units and 5,360,912 subordinated units, representing 74.9% and 25%, respectively, limited partner interests in us (17,561,294 common units and 5,360,912 subordinated units, representing 76.5% and 23.4%, respectively, limited partner interests in us if the underwriters exercise in full their option to purchase additional common units). The general partner will own 21,444 general partner units, or 22,945 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 $177 million from this offering, based upon the assumed initial public offering price of $20.00 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 $0.4750 per unit per quarter on all common, subordinated and general partner units ($1.90 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 December 31, 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 $0.4750 plus any arrearages from prior quarters;


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• 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 $0.4750; and
 
• third, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until each unit has received a distribution of $0.54625.
 
If cash distributions to our unitholders exceed $0.54625 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 $47.3 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 September 30, 2011 was approximately $39.6 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 $0.42 per unit on our subordinated units, or a quarterly distribution of $0.29 per unit on our subordinated units assuming the underwriters exercise in full their option to purchase additional common units, during that period.
 
We have not calculated available cash on a pro forma quarter-by-quarter basis for the year ended December 31, 2010 or the twelve months ended September 30, 2011 to determine if we would have generated available cash sufficient to pay the minimum quarterly distribution for each individual quarter during those periods. For a calculation of our ability to have made distributions to our unitholders based on our pro forma results of operations for the year ended December 31, 2010 and the twelve months ended


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September 30, 2011, please read “Our Cash Distribution Policy and Restrictions on Distributions.”
 
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 $40.7 million (or an average of approximately $10.2 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 December 31, 2012,” that we will have sufficient available cash to pay the aggregate minimum quarterly distribution of $10.2 million on all of our common units, general partner units and subordinated units for the twelve months ending December 31, 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 on or after December 31, 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 and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaling or exceeding the minimum quarterly distribution payable with respect to a period of twelve consecutive quarters immediately preceding such date, provided there are no arrearages in the minimum quarterly distribution on our common units at that time.
 
The subordination period will also end if our general partner is removed other than for cause, provided that units held by our general partner and its affiliates are not 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.


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Early conversion of subordinated units If we have earned and paid from operating surplus at least $0.59375 (125% of the minimum quarterly distribution) for each quarter in any four consecutive quarter period ending on or after December 31, 2012 on each outstanding common unit, subordinated unit, general partner unit and any other partnership interest that is senior or equal in right of distribution to the subordinated units, in addition to the corresponding incentive distributions for each such quarter, all of the outstanding subordinated units will convert into common units.
 
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 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 53.3% of our outstanding common and subordinated units (or 49.8% 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 37.7% of our outstanding common units (or 34.5% 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 December 31, 2014, such unitholders will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 25% of the cash distributed to such unitholders with respect to that period. Please read “Material Tax Consequences — Tax Consequences of Unit


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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.”
 
Directed unit program At our request, the underwriters have reserved up to 5% of the common units being offered by this prospectus for sale at the initial public offering price to officers and directors of our general partner. For further information regarding our directed unit program, please read “Underwriting.”
 
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 have applied to list our common units on the NASDAQ Global Market under the symbol “MEMP.”


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Summary Historical and Pro Forma Financial Data
 
We were formed in April 2011 and do not have historical financial operating results. The following table shows summary historical financial data of our predecessor, which consists of the combined financial data of BlueStone Natural Resources Holdings, LLC, certain oil and natural gas properties owned by Classic Hydrocarbons Holdings, L.P. and for periods after April 8, 2011, certain oil and natural gas properties of WHT Energy Partners LLC, and unaudited pro forma combined financial data of Memorial Production Partners LP, for the periods and as of the dates presented. Due to the factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Historical and Pro Forma Financial and Operating 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 future results of operations will not be comparable to the historical results of our predecessor.
 
The summary historical combined financial data as of December 31, 2009 and 2010 and for the years ended December 31, 2008, 2009 and 2010 are derived from the audited historical combined financial statements of our predecessor included elsewhere in this prospectus. The summary historical combined financial data as of September 30, 2010 and 2011 and for the nine months ended September 30, 2010 and 2011 are derived from the unaudited historical combined financial statements of our predecessor included elsewhere in this prospectus.
 
The summary unaudited pro forma financial data as of September 30, 2011 and for the nine months ended September 30, 2011 and the year ended December 31, 2010 are derived from the unaudited pro forma combined financial statements of Memorial Production Partners LP included elsewhere in this prospectus. The pro forma adjustments have been prepared as if certain transactions, which have been completed or which will be effected prior to or in connection with the closing of this offering, had taken place on September 30, 2011, in the case of the unaudited pro forma balance sheet, or as of January 1, 2010, in the case of the unaudited pro forma statements of operations. These transactions include:
 
  •  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 6,061,294 common units, 5,360,912 subordinated units and $307 million in cash (based on the midpoint of the price range set forth on the cover page of this prospectus) and the issuance to our general partner of 21,444 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 10,000,000 common units in this offering and the application of the net proceeds as described in “Use of Proceeds”; and
 
  •  our borrowing of approximately $130 million under our new $1.0 billion revolving credit facility and the application of the net proceeds as described in “Use of Proceeds.”
 
You should read the following table in conjunction with “— Our Partnership Structure and Formation Transactions,” “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the historical combined financial statements of our predecessor and the unaudited pro forma combined financial statements of Memorial Production Partners LP included elsewhere in this prospectus. Among other things, those historical and unaudited pro forma combined financial statements include more detailed information regarding the basis of presentation for the following information.


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The following table presents Adjusted EBITDA, which we use in evaluating the liquidity of our business. This financial measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain this measure below and reconcile it to net cash from operating activities, its most directly comparable financial measure calculated and presented in accordance with GAAP.
 
                                                         
                                  Memorial Production
 
                                  Partners LP
 
    Our Predecessor     Pro Forma  
                      Nine
 
                      Months
 
          Nine Months Ended
    Year Ended
    Ended
 
    Year Ended December 31,     September 30,     December 31,     September 30,  
    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     $ 25,950     $ 54,086     $ 87,762     $ 65,463  
Other income
    622       319       1,433       1,395       599       1,404       588  
                                                         
Total revenues
    49,935       24,860       38,741       27,345       54,685       89,166       66,051  
Costs and expenses:
                                                       
Lease operating
    8,843       11,207       13,974       9,343       18,172       23,052       19,358  
Exploration
    374       2,690       39             56       36        
Production taxes
    3,127       1,464       2,112       1,446       3,259       7,387       4,854  
Depreciation, depletion and amortization
    12,353       15,226       20,066       14,067       17,840       34,772       21,371  
Impairment of proved oil and natural gas properties
    14,166       3,480       11,800       5,048       3,047       9,509        
General and administrative
    3,835       4,811       6,116       3,765       5,765       5,819       5,585  
Accretion
    224       320       663       448       748       1,072       800  
Gain on derivative instruments
    (9,815 )     (10,834 )     (10,264 )     (12,173 )     (13,785 )     (10,264 )     (13,785 )
Gain on sale of properties
    (7,395 )     (7,851 )     (1 )           (62,764 )           (62,020 )
Other, net
          304       890       891       802       890       802  
                                                         
Total costs and expenses
    25,712       20,817       45,395       22,835       (26,860 )     72,273       (23,035 )
Operating income (loss)
    24,223       4,043       (6,654 )     4,510       81,545       16,893       89,086  
Interest expense
    (3,138 )     (2,937 )     (4,438 )     (3,405 )     (5,433 )     (4,105 )     (3,079 )
Income (loss) before income taxes
  $ 21,085     $ 1,106     $ (11,092 )   $ 1,105     $ 76,112     $ 12,788     $ 86,007  
                                                         
Income tax expense
                (225 )           (122 )     (225 )     (122 )
                                                         
Net income (loss)
  $ 21,085     $ 1,106     $ (11,317 )   $ 1,105     $ 75,990     $ 12,563     $ 85,885  
                                                         
Cash Flow Data:
                                                       
Net cash provided by operating activities
  $ 32,838     $ 12,672     $ 20,288     $ 16,670     $ 26,125                  
Net cash (used in) investing activities
    (45,547 )     (24,947 )     (116,687 )     (109,808 )     (156,240 )                
Net cash provided by financing activities
    11,619       15,989       96,756       95,122       134,509                  
Other Financial Data:
                                                       
Adjusted EBITDA
  $ 33,644     $ 24,953     $ 23,833     $ 17,662     $ 31,658     $ 60,202     $ 40,423  
 


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            Memorial
            Production
                    Partners LP
    Our Predecessor   Pro Forma
    Year Ended December 31,   As of September 30,
  As of September 30,
    2008   2009   2010   2011   2011
                (Unaudited)   (Unaudited)
    (In thousands)
 
Balance Sheet Data:
                                       
Working capital
  $ (966 )   $ 9,494     $ 4,116     $ 15,265     $ 8,480  
Total assets
    145,529       146,153       248,540       469,324       433,055  
Total debt
    62,536       61,784       115,428       203,228       130,000  
Partners’ capital
    54,576       72,988       105,801       229,436       285,656  
 
Non-GAAP Financial Measure
 
We include in this prospectus the non-GAAP financial measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income (loss):
 
  •  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;
 
  •  Acquisition related 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.
 
We expect that we will be required to comply with certain Adjusted EBITDA-related metrics under our new revolving credit facility.
 
Adjusted EBITDA will be used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess:
 
  •  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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  •  the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make distributions on our units.
 
In addition, our management will use Adjusted EBITDA to evaluate actual cash flow available to pay distributions to our unitholders, develop existing reserves, or acquire additional oil and natural gas properties.
 
Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents our calculation of Adjusted EBITDA. The table below further presents a reconciliation of Adjusted EBITDA to net cash flows provided by operating activities, our most directly comparable GAAP financial measure, for each of the periods indicated.
 
Calculation of Adjusted EBITDA
 
                                                         
                      Memorial Production
 
                                  Partners LP
 
    Our Predecessor     Pro Forma  
                                  Year
    Nine
 
                                  Ended
    Months
 
                      Nine Months Ended
    December
    Ended
 
    Year Ended December 31,     September 30,     31,
    September 30,
 
    2008     2009     2010     2010     2011     2010     2011  
                      (Unaudited)     (Unaudited)  
    (In thousands)  
 
Net income (loss)
  $ 21,085     $ 1,106     $ (11,317 )   $ 1,105     $ 75,990     $ 12,563     $ 85,885  
Interest expense
    3,138       2,937       4,438       3,405       5,433       4,105       3,079  
Income tax expense
                225             122       225       122  
Depreciation, depletion and amortization
    12,353       15,226       20,066       14,067       17,840       34,772       21,371  
Impairment
    14,166       3,480       11,800       5,048       3,047       9,509        
Accretion of asset retirement obligations
    224       320       663       448       748       1,072       800  
Unrealized (gains) losses on commodity derivative instruments
    (10,301 )     6,741       (2,970 )     (7,301 )     (9,656 )     (2,970 )     (9,656 )
Acquisition related costs
          304       890       890       842       890       842  
Gain on sale of properties
    (7,395 )     (7,851 )     (1 )           (62,764 )           (62,020 )
Unit-based compensation expense
                                         
Exploration costs
    374       2,690       39             56       36        
                                                         
Adjusted EBITDA
  $ 33,644     $ 24,953     $ 23,833     $ 17,662     $ 31,658     $ 60,202     $ 40,423  
                                                         
 
Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA
 
                                                         
    Our Predecessor              
          Nine Months Ended
             
    Year Ended December 31,     September 30,              
    2008     2009     2010     2010     2011              
                      (Unaudited)              
    (In thousands)              
 
Net cash provided by operating activities
  $ 32,838     $ 12,672     $ 20,288     $ 16,670     $ 26,125                  
Changes in working capital
    (1,979 )     8,840       (742 )     (2,249 )     (1,595 )                
Interest expense
    3,138       2,937       4,438       3,405       5,433                  
Premiums paid for derivatives
                            2,847                  
Premiums received for derivatives
                            (1,008 )                
Unrealized gain/(loss) on interest rate swaps
    (327 )     309       (296 )     (452 )     (649 )                
Acquisition related costs
          304       890       890       842                  
Amortization of deferred financing fees
    (26 )     (109 )     (745 )     (602 )     (337 )                
                                                         
Adjusted EBITDA
  $ 33,644     $ 24,953     $ 23,833     $ 17,662     $ 31,658                  
                                                         


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Summary Reserve and Pro Forma Operating Data
 
The following tables present summary data with respect to our estimated pro forma net proved oil and natural gas reserves and pro forma operating data as of the dates presented.
 
The reserve estimates attributable to the Partnership Properties at December 31, 2010 presented in the table below are 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. All of these reserve estimates were prepared in accordance with the SEC’s rules regarding oil and natural gas reserve reporting that are currently in effect. The following tables also contain certain summary unaudited information regarding production and sales of oil and natural gas with respect to such properties.
 
Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business and Properties — Oil and Natural Gas Data and Operations — Properties — Estimated Proved Reserves” and the reserve report and reserve audit report summaries included in this prospectus in evaluating the material presented below. The summaries of our reserve reports are included as Appendices C, D and E of this prospectus.
 
Reserve Data
 
         
    Partnership
 
    Properties as of
 
    December 31,
 
    2010  
 
Estimated Pro Forma Proved Reserves
       
Oil (MBbls)
    2,002  
NGLs (MBbls)
    4,502  
Natural gas (MMcf)
    285,676  
         
Total (MMcfe)(1)
    324,697  
Proved developed (MMcfe)
    264,572  
Proved undeveloped (MMcfe)
    60,125  
Proved developed reserves as a percentage of total proved reserves
    81 %
Standardized measure (in millions)(2)(3)
  $ 359.2  
Oil and Natural Gas Prices(4)
       
Oil — WTI Posting (Plains) per Bbl
  $ 75.96  
Natural 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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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 Production
    Partners LP
    Pro Forma
        Nine Months
    Year Ended
  Ended
    December 31,
  September 30,
    2010   2011
    (Unaudited)
 
Production and operating data:
               
Net production volumes:
               
Oil (MBbls)
    107       73  
NGLs (MBbls)
    272       164  
Natural gas (MMcf)
    16,713       11,873  
                 
Total (MMcfe)
    18,985       13,299  
Average net production (MMcfe/d)
    52       49  
Average sales price:(1)
               
Oil (per Bbl)
  $ 74.35     $ 89.82  
NGLs (per Bbl)
  $ 37.41     $ 49.05  
Natural gas (per Mcf)
  $ 4.17     $ 4.28  
Average price per Mcfe
  $ 4.62     $ 4.92  
Average unit costs per Mcfe:
               
Lease operating expenses
  $ 1.21     $ 1.46  
Production taxes
  $ 0.39     $ 0.37  
General and administrative expenses
  $ 0.31     $ 0.42  
Depreciation, depletion and amortization
  $ 1.83     $ 1.61  
 
 
(1) Prices do not include the effects of derivative cash settlements.


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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.
 
We may not have sufficient available cash each quarter to pay the minimum quarterly distribution of $0.4750 per unit or any other amount. Under the terms of our partnership agreement, the amount of cash available for distribution will be reduced by our operating expenses and the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including acquisitions of additional oil and natural gas properties, future debt service requirements and future cash distributions to our unitholders.
 
The amount of cash we distribute on our units principally depends on the cash we generate from operations, which depends on, among other things:
 
  •  the amount of oil, natural gas and NGLs we produce;
 
  •  the prices at which we sell our oil, natural gas and NGL production;
 
  •  the amount and timing of settlements of our commodity derivatives;
 
  •  the level of our operating costs, including maintenance capital expenditures and payments to our general partner; and
 
  •  the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon.
 
For a description of additional restrictions and factors that may affect our ability to make cash distributions to our unitholders, please read “Our Cash Distribution Policy and Restrictions on Distributions.”
 
We would not have generated sufficient available cash on a pro forma basis to have paid the minimum quarterly distribution on all of our units for the twelve months ended September 30, 2011.
 
We would be required to distribute $40.7 million on an aggregate basis per year to distribute the minimum quarterly distribution of $0.4750 to all outstanding units, assuming the underwriters do not exercise their option to purchase additional common units, and $43.6 million on an aggregate basis if the underwriters exercise their option to purchase additional common units in full. If we had completed the formation transactions contemplated in this prospectus and the acquisition of all of the Partnership Properties on October 1, 2010, our unaudited pro forma available cash generated during the twelve months ended September 30, 2011 would have been approximately $39.6 million. As a result, this amount would have been insufficient to make a cash distribution for the twelve months ended September 30, 2011 at the minimum quarterly distribution of $0.4750 per unit per quarter on all of our outstanding units during that period regardless of whether the underwriters exercise their option to purchase additional common units.
 
We have not calculated available cash on a pro forma quarter-by-quarter basis for the year ended December 31, 2010 or the twelve months ended September 30, 2011 to determine if we would have generated


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available cash sufficient to pay the minimum quarterly distribution for each quarter during those periods. As a private company, our predecessor was not required to prepare quarterly financial information for all periods and we have not prepared quarterly financial information for all periods shown in this prospectus. In addition, a significant portion of the Partnership Properties were acquired during 2011 and we have not been provided by the sellers, and thus do not have access to, quarter-by-quarter financial information with respect to those assets prior to our acquisition. Accordingly, we cannot and have not used or relied upon quarter-by-quarter financial information to determine if we would have generated available cash sufficient to pay the minimum quarterly distribution for each quarter during those periods. Rather, we have based our determination whether we would have generated sufficient available cash to pay the minimum quarterly distribution for each quarter during the applicable period on financial information for the entire four quarter period. Please read “Our Cash Distribution Policy and Restrictions on Distributions — Unaudited Pro Forma Available Cash for the Year Ended December 31, 2010 and Twelve Months Ended September 30, 2011.”
 
The assumptions underlying the forecast of cash available for distribution that we include in “Our Cash Distribution Policy and Restrictions on Distributions” may prove inaccurate and are subject to significant risks and uncertainties, which could cause actual results to differ materially from our forecasted results.
 
The forecast of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions on Distributions” includes our forecast of our results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending December 31, 2012. The assumptions underlying the forecast may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from our forecasted results. If our actual results are significantly below forecasted results, or if our expenses are greater than forecasted, we may not generate enough cash available for distribution to pay the minimum quarterly distribution or any amount on our common units or subordinated units, which may cause the market price of our common units to decline materially.
 
Unless we replace the oil and natural gas reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.
 
We will be unable to sustain our minimum quarterly distribution without substantial capital expenditures that maintain our asset base. Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production and therefore our cash flow and ability to make distributions are highly dependent on our success in efficiently developing and exploiting our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we drill additional wells or make acquisitions. We may not be able to develop, find or acquire additional reserves to replace our current and future production at economically acceptable terms, which would adversely affect our business, financial condition and results of operations and reduce cash available for distribution to our unitholders.
 
None of the proceeds of this offering will be used to maintain or grow our asset base or be reserved for future distributions.
 
None of the proceeds of this offering will be used to maintain or grow our asset base, which may be necessary to cover future distributions to our unitholders, and none of the proceeds will be reserved for future distributions to our unitholders. The proceeds of this offering, together with borrowings under our new revolving credit facility, will be used as partial consideration for the Partnership Properties, which will be contributed to us by Memorial Resource at the closing of this offering.
 
Our acquisition and development operations require substantial capital expenditures.
 
The development and production of our oil and natural gas reserves requires substantial capital expenditures, which will reduce the amount of cash available for distribution to our unitholders. Further, if the borrowing base under our new revolving credit facility decreases, or our revenues decrease, as a result of


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lower oil or natural gas prices, we may not be able to obtain the capital necessary to sustain our operations at the expected levels necessary to generate an amount of cash sufficient to make distributions to our unitholders.
 
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.
 
Lower oil and natural gas prices may decrease our revenues and thus cash available for distribution to our unitholders. Historically, oil and natural gas prices have been extremely volatile. For example, for the five years ended December 31, 2010, the NYMEX-WTI oil price ranged from a high of $145.29 per Bbl to a low of $31.41 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $13.31 per MMBtu to a low of $1.83 per MMBtu. From January 1, 2011 to November 1, 2011, the NYMEX-WTI oil price ranged from a high of $113.93 per Bbl to a low of $75.67 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $4.85 per MMBtu to a low of $3.48 per MMBtu. A significant decrease in commodity prices may cause us to reduce the distributions we pay to our unitholders or to cease paying distributions.
 
If commodity prices decline and remain depressed for a prolonged period, a significant portion of our development projects may become uneconomic and cause write downs of the value of our oil and natural gas properties, which may adversely affect our financial condition and our ability to make distributions to our unitholders.
 
Significantly lower oil and natural gas prices would render many of our development and production projects uneconomical and result in a downward adjustment of our reserve estimates, which would reduce our borrowing base and our ability to pay distributions or fund our operations.
 
Further, deteriorating commodity prices may cause us to recognize impairments in the value of our oil and natural gas properties. In addition, if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken, our ability to borrow funds under our new revolving credit facility and 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.
 
The prices that we receive for our oil and natural gas production often reflect a regional discount, based on the location of production, to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. These discounts, if significant, could reduce our cash available for distribution to our unitholders and adversely affect our financial condition.
 
Our hedging strategy may not effectively mitigate the impact of commodity price volatility from our cash flows, and our hedging activities could result in cash losses and may limit potential gains.
 
The prices at which we enter into commodity derivative contracts covering our production in the future will be dependent upon oil and natural gas prices, and price expectations, at the time we enter into these transactions, which may be substantially higher or lower than current or future oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Many of the derivative contracts to which we will be a party will require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil and natural gas prices. If our actual production and sales for any period are less than our hedged production and sales for that period (including reductions in production due to operational delays) or if we are unable to perform our drilling activities as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, which may materially impact our liquidity.


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Our hedging transactions will expose us to counterparty credit risk.
 
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the derivative contract and, accordingly, prevent us from realizing the benefit of the derivative contract.
 
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.
 
It is not possible to measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering is complex, requiring subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, future production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. For example, if the prices used in our reserve reports had been $10.00 less per barrel for oil and $1.00 less per MMBtu for natural gas, then the standardized measure of our estimated proved reserves as of that date on a pro forma basis, excluding the effects of our commodity derivative contracts, would have decreased by $127.2 million, from $359.2 million to $232.0 million.
 
Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
 
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.
 
The present value of future net cash flows from our proved reserves, or standardized measure, may not be the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average oil and gas index prices, calculated as the un-weighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the FASB in Accounting Standards Codification (“ASC”) 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.
 
Developing and producing oil and natural gas are costly and high-risk activities with many uncertainties.
 
Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. Our development and production operations may incur unscheduled costs or otherwise be curtailed, delayed or canceled as a result of other factors, including:
 
  •  high costs, shortages or delivery delays of rigs, equipment, labor or other services;
 
  •  composition of sour natural gas, including sulfur, carbon dioxide and other diluent content;
 
  •  unexpected operational events and conditions;
 
  •  failure of down hole equipment and tubulars;
 
  •  loss of wellbore mechanical integrity;
 
  •  hydrocarbon or oilfield chemical spills;
 
  •  adverse weather conditions and natural disasters;


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  •  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;
 
  •  loss of drilling fluid circulation;
 
  •  fires, blowouts, surface craterings and explosions; and
 
  •  surface spills or underground migration due to uncontrollable flows of oil, natural gas, formation water or well fluids.
 
If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and cash available for distribution to our unitholders.
 
Many of our properties are in areas that may have been partially depleted or drained by offset wells.
 
Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests lying contiguous or adjacent to or adjoining any of our properties could take actions, such as drilling additional wells, that could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves, and may inhibit our ability to further exploit and develop our reserves.
 
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.
 
We have identified drilling, recompletion and development locations and prospects for future drilling, recompletion and development. These drilling, recompletion and development locations represent a significant part of our future drilling and enhanced recovery opportunity plans. Our ability to drill, recomplete and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, the generation of additional seismic or geological information, the availability of drilling rigs, and drilling results. Because of these uncertainties, we cannot be certain of the timing of these activities or that they will ultimately result in the realization of estimated proved reserves or meet our expectations for success. As such, our actual drilling and enhanced recovery activities may materially differ from our current expectations, which could have a significant adverse effect on our estimated reserves, financial condition and results of operations, and as a result, our ability to make cash distributions to our unitholders.
 
Shortages of rigs, equipment and crews could delay our operations, increase our costs and delay forecasted revenue.
 
Higher oil and natural gas prices generally increase the demand for rigs, equipment and crews and can lead to shortages of, and increasing costs for, development equipment, services and personnel. Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict Memorial Resource’s ability to drill the wells and conduct the operations that it currently has planned relating to the fields where the Partnership Properties are located. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and reduce our cash available for distribution to our unitholders.
 
If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.
 
Our ability to grow and to increase distributions to our unitholders depends in part on our ability to make acquisitions that result in an increase in available cash per unit. We may be unable to make such acquisitions because we are:
 
  •  unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with their owners;


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  •  unable to obtain financing for such acquisitions on economically acceptable terms; or
 
  •  outbid by competitors.
 
If we are unable to acquire properties containing estimated proved reserves, our total level of estimated proved reserves will decline as a result of our production, and we will be limited in our ability to increase or possibly even to maintain our level of cash distributions to our unitholders.
 
Any acquisitions we complete will be subject to substantial risks.
 
One of our growth strategies is to acquire additional oil and natural gas reserves from time to time. Even if we do make acquisitions that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit. Any acquisition involves potential risks, including, among other things:
 
  •  the validity of our assumptions about estimated proved reserves, future production, revenues, capital expenditures, operating expenses and costs;
 
  •  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; and
 
  •  the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.
 
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data and other information, the results of which are often inconclusive and subject to various interpretations. Our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition, given time constraints imposed by sellers. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.
 
Adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.
 
Our properties are located in South and East Texas. An adverse development in the oil and natural gas business of these geographic areas, such as in our ability to attract and retain field personnel, could have an impact on our results of operations and cash available for distribution 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.
 
Under our omnibus agreement, Memorial Resource will handle sales of our natural gas, oil and NGL production on our behalf, which will depend upon the demand for natural gas, oil and NGLs from potential


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purchasers of our production. In recent years, a number of energy marketing and trading companies have discontinued their marketing and trading operations, which has significantly reduced the number of potential purchasers for our production. This reduction in potential customers has reduced overall market liquidity. If any one or more of our significant customers reduces the volume of oil and natural gas production it purchases and other customers to sell those volumes to are unable to be found, then the volume of our production sold on our behalf could be reduced, and we could experience a material decline in cash available for distribution.
 
In addition, a failure by any of these companies, or any purchasers of our production, to perform their payment obligations to us could have a material adverse effect on our results of operation. To the extent that purchasers of our production rely on access to the credit or equity markets to fund their operations, there could be an increased risk that those purchasers could default in their contractual obligations to us. If for any reason we were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of our production were uncollectible, we would recognize a charge in the earnings of that period for the probable loss and could suffer a material reduction in our liquidity and ability to make distributions to our unitholders.
 
We may be unable to compete effectively with larger companies.
 
The oil and natural gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas, and securing equipment and trained personnel. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Furthermore, we may not be able to aggregate sufficient quantities of production to compete with larger companies that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to our production. Any inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations and our ability to make distributions to our unitholders.
 
We may incur additional debt to enable us to pay our quarterly distributions.
 
We may be unable to pay the minimum quarterly distribution or the then-current distribution rate without borrowing under our new revolving credit facility or otherwise. If we use borrowings to pay distributions to our unitholders for an extended period of time rather than to fund capital expenditures and other activities relating to our operations, we may be unable to maintain or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness incurred to pay these distributions, will reduce our cash available for distribution on our units and will have a material adverse effect on our business, financial condition and results of operations. If we borrow to pay distributions to our unitholders during periods of low commodity prices and commodity prices remain low, we may have to reduce our distribution to our unitholders to avoid excessive leverage.
 
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.
 
We expect that our new revolving credit facility will restrict, among other things, our ability to incur debt and pay distributions, and will require us to comply with customary financial covenants and specified financial ratios. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our new revolving credit facility that are not cured or waived within the specified time periods, a significant portion of our indebtedness may become immediately due and


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payable, and we will be prohibited from making distributions to our unitholders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our new revolving credit facility will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our new revolving credit facility, the lenders could seek to foreclose on our assets. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — New Revolving Credit Facility” for additional detail regarding the covenants and restrictive provisions to be included in our new revolving credit facility.
 
Our new revolving credit facility will allow us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base will be subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated natural gas, oil and NGL reserves, which will take into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. If we are unable to repay any borrowings in excess of a decreased borrowing base, we would be in default and no longer able to make any distributions to our unitholders.
 
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.
 
The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of pipelines and other transportation methods, gathering systems and processing facilities owned by third parties. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of contracted capacity on such systems. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or processing facility capacity could reduce our ability to market our oil and natural gas production and harm our business.
 
The operation of our properties is largely dependent on the ability of Memorial Resource’s employees.
 
The continuing production from a property, and to some extent the marketing of production, is dependent upon the ability of the operators of our properties. Memorial Resource will operate substantially all of the Partnership Properties, either directly as operator or, where we are the operator of record, on our behalf. As of December 31, 2010, we operate 65%, Memorial Resource operates 29% and third parties operate 6% of the wells and properties in which we have interests. As a result, the success and timing of drilling and development activities on such properties, depend upon a number of factors, including:
 
  •  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.
 
If Memorial Resource or the applicable third party operator is unable to conduct drilling and development activities on our properties on a timely basis, we may be unable to increase our production or offset normal production declines, or we will be required to write off the estimated proved reserves attributable thereto, any


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of which may adversely affect our production, revenues and results of operations and our cash available for distribution. Any such write-offs of our reserves could reduce our ability to borrow money and could adversely impact our ability to pay distributions on the common units.
 
Where we are operator of the wells located on our properties, our operations will be generally governed by operating agreements if any third party has interests in these properties, which agreements typically require the operator to conduct operations in a good and workmanlike manner. For the wells located on our properties that Memorial Resource or a third party is the operator, the operator will generally not be a fiduciary with respect to us or our unitholders. As an owner of working interests in properties not operated by us, we will generally have a cause of action for damages arising from a breach of the operator’s duty.
 
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.
 
Our oil and natural gas development and production operations are subject to complex and stringent laws and regulations. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition, and results of operations.
 
Our oil and natural gas development and production operations are also subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly compliance or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue.
 
Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.
 
See “Business and Properties — Environmental Matters and Regulation” for a further description of the laws and regulations that affect us.


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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.
 
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” (“GHGs”), including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere and other climatic changes. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of GHGs. One bill approved by the U.S. House of Representatives in June 2009, known as the American Clean Energy and Security Act of 2009, would have required an 80% reduction in emissions of GHGs from sources within the U.S. between 2012 and 2050 but was not approved by the U.S. Senate in the 2009-2010 legislative session. The U.S. Congress is likely to continue to consider similar bills. Moreover, almost half of the states have already taken legal measures to reduce emissions of GHGs, through the planned development of GHG emission inventories and/or regional GHG cap and trade programs or other mechanisms. Most cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Some states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources.
 
In addition, in December 2009, the U.S. Environmental Protection Agency (the “EPA”) determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which would regulate emissions of GHGs from large stationary sources of emissions such as power plants or industrial facilities. The motor vehicle rule was finalized in April 2010 and became effective in January 2011 but it does not require immediate reductions in GHG emissions. The stationary source rule was adopted in May 2010 and also became effective January 2011 and is the subject of several pending lawsuits filed by industry groups and Congress is considering legislation to limit or strip the EPA’s authority to regulate GHGs. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. The EPA also plans to implement GHG emissions standards for power plants in May 2012 and for refineries in November 2012.
 
The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. Please read “Business and Properties — Environmental Matters and Regulation.”
 
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 operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations


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become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders. Please read “Business and Properties — Environmental Matters and Regulation” and “Business and Properties — Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect the third parties on whom we rely.
 
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.
 
The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”) provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission, or CFTC, adopt rules or regulations implementing the Act and providing definitions of terms used in the Act. The Act establishes margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities. Many of the regulations necessary to implement the Act and define terms used in the Act have not been adopted. As a result, we do not yet know if we will be required to comply with margin requirements and clearing and trade-execution requirements imposed by the Act or if certain of our counterparties will be required to spin off some of our derivatives contracts to separate entities, which may not be as credit-worthy as our current counterparties. The Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and fund unitholder distributions. Finally, the Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.
 
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays, and adversely affect our production.
 
We routinely apply hydraulic fracturing techniques in many of our U.S. onshore oil and natural-gas drilling and completion programs. The process is typically regulated by state oil and natural gas commissions; however, the EPA recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel as an additive under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process.
 
Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas (RCT) and the public of certain information regarding the components used in the hydraulic fracturing process. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.


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There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands.
 
Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanism.
 
Furthermore, on August 23, 2011, the EPA published a proposed rule in the Federal Register to establish new emissions standards to reduce volatile organic compounds (“VOC”) emissions from several types of processes and equipment used in the oil and gas industry, including a 95 percent reduction in VOCs emitted during the construction or modification of hydraulically-fractured wells.
 
Finally, on October 20, 2011, the EPA announced its plan to propose federal pre-treatment standards for wastewater generated during the hydraulic fracturing process. Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting “flowback,” as well as “produced water.” The EPA asserts that this water may contain radioactive materials and other pollutants and, therefore, may deteriorate drinking water quality if not properly treated before discharge. The Clean Water Act prohibits the discharge of wastewater into federal or state waters. Thus “flowback” and “produced water” must either be injected into permitted disposal wells or transported to public or private treatment facilities for treatment. The EPA asserts that due to some contaminants in hydraulic fracturing wastewater, most treatment facilities are unable to properly treat the wastewater before introducing it into public waters. If adopted, the new pretreatment rules will require shale gas operations to pretreat wastewater before transferring it to treatment facilities.
 
If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.
 
Recently proposed rules regulating air emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs.
 
On August 23, 2011, the EPA published a proposed rule in the Federal Register that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and VOCs and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal requires the


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reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rule also establishes specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, the rule establishes new leak detection requirements for natural gas processing plants. The EPA is currently receiving public comment and recently conducted public hearings regarding the proposed rules and must take final action on them by April 3, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
 
Increases in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.
 
Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Also, as with other yield-oriented securities, our unit price is impacted by the level of our cash distributions to our unitholders and the implied distribution yield. The distribution yield is often used by investors to compare and rank similar yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue additional equity or incur debt, and the cost to us of any such issuance or incurrence.
 
Expenses not covered by our insurance could have a material adverse effect on our financial position, results of operations and cash flows.
 
We maintain insurance coverage against potential losses that we believe is customary in the industry. However, these policies may not cover all liabilities, claims, fines, penalties or costs and expenses that we may incur in connection with our business and operations, including those related to environmental claims. In addition, we cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
 
Risks Inherent in an Investment in Us
 
Our general partner and its affiliates will 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.
 
Our general partner will have control over all decisions related to our operations. Upon consummation of this offering, Memorial Resource will control an aggregate 37.7% of our outstanding common units and all of our subordinated units, and 100% of the voting membership interests in our general partner will be owned by Memorial Resource. The Funds, in turn, collectively own 100% of Memorial Resource. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to the owners of our general partner. However, certain directors and officers of our general partner are directors and/or officers of affiliates of our general partner (including Memorial Resource, the Funds and NGP), and certain of our general partner’s executive officers and directors will continue to have economic interests, investments and other economic incentives in the Funds and other NGP-affiliated entities. Conflicts of interest may arise in the future between our general partner and its affiliates (including Memorial Resource, the Funds and NGP), on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders and us. Please read “Conflicts of Interest and Fiduciary Duties — Conflicts of Interest — Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies


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available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.” These potential conflicts include, among others, the following situations:
 
  •  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 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 $30.5 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;


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  •  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.
 
Please read “Certain Relationships and Related Party Transactions” and “Conflicts of Interest and Fiduciary Duties.”
 
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.
 
Our partnership agreement provides that Memorial Resource and the Funds and their respective affiliates (including NGP and its affiliates’ portfolio investments) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Memorial Resource and the Funds and their respective affiliates may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets.
 
NGP and the Funds are established participants in the oil and natural gas industry, and have resources greater than ours, which factors may make it more difficult for us to compete with them with respect to commercial activities as well as for potential acquisitions. As a result, competition from these affiliates could adversely impact our results of operations and cash available for distribution to our unitholders. Please read “Conflicts of Interest and Fiduciary Duties.”
 
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.
 
Neither we nor our general partner have any employees and we will rely solely on Memorial Resource to operate our assets. Upon consummation of this offering, we and our general partner will enter into an omnibus agreement with Memorial Resource, pursuant to which, among other things, Memorial Resource will agree to operate our assets and perform other management, administrative, and operating services for us and our general partner.
 
Memorial Resource will provide substantially similar activities with respect to its own assets and operations. Because Memorial Resource will be providing services to us that are substantially similar to those performed for itself, Memorial Resource may not have sufficient human, technical and other resources to provide those services at a level that Memorial Resource would be able to provide to us if it were solely focused on our business and operations. Memorial Resource may make internal decisions on how to allocate


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its available resources and expertise that may not always be in our best interest compared to Memorial Resource’s interests. There is no requirement that Memorial Resource favor us over itself in providing its services. If the employees of Memorial Resource and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.
 
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.
 
Prior to the completion of this offering, certain entities that comprise our predecessor have been private entities with limited accounting personnel and other supervisory resources to adequately execute their accounting processes and address their internal control over financial reporting. In connection with our predecessor’s audit for the year ended December 31, 2010, our predecessor’s independent registered accounting firm identified and communicated material weaknesses related to lack of accounting personnel with sufficient technical accounting experience for certain significant or unusual transactions and lack of management review at the appropriate level for certain non-routine areas. A “material weakness” is a deficiency, or combination of deficiencies, in internal controls such that there is a reasonable possibility that a material misstatement of our predecessor’s financial statements will not be prevented, or detected in a timely basis. The lack of technical accounting experience and management review resulted in several audit adjustments to the financial statements for the year ended December 31, 2010, 2009, and 2008.
 
After the closing of this offering, our management team and financial reporting oversight personnel will be those of Memorial Resource and our predecessor, and thus, we may face the same material weaknesses described above.
 
We are in the early phases of evaluating the design and operation of our internal control over financial reporting and will not complete our review until after this offering is completed. We cannot predict the outcome of our review at this time. During the course of the review, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses, in addition to the material weaknesses described above. Each of the material weaknesses described above could result in a misstatement of our accounts or disclosures that would result in a material misstatement of our annual or interim combined financial statements that would not be prevented or detected. We cannot assure you that the measures we have taken to date, or any measures we may take in the future, will be sufficient to remediate the material weaknesses described above or avoid potential future material weaknesses.
 
We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a publicly traded partnership, we will be required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we will be required to disclose changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a publicly traded partnership, we will need to implement additional internal controls, reporting systems and procedures and hire additional accounting, finance and legal staff.
 
Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting until the year following our first annual report required to be filed with the SEC. If it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed or operating. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.


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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.
 
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on 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.
 
To maintain and increase our levels of production, we will need to acquire oil and gas properties. All of the officers of our general partner hold similar positions with Memorial Resource, and many of the directors of our general partner, who are responsible for managing our general partner’s direction of our operations and acquisition activities, hold positions of responsibility with other entities (including NGP-affiliated entities) that are in the business of identifying and acquiring oil and natural gas properties. For example, the Funds and their affiliates (including NGP) are in the business of investing in oil and natural gas companies with independent management teams that also seek to acquire oil and natural gas properties, and Memorial Resource is in the business of acquiring and developing oil and natural gas properties. Mr. Hersh, a director of our general partner, is the Chief Executive Officer of NGP Energy Capital Management and a managing partner of NGP; Mr. Gieselman, a director of our general partner, is a managing director of NGP; Mr. Weber, a director of our general partner, is a managing director of NGP and serves as Chief Investment Coordinator for NGP; and Mr. Weinzierl, the President, Chief Executive Officer and Chairman of the board of directors of our general partner, was a managing director and operating partner of NGP prior to assuming his current positions with Memorial Resource and our general partner and continues to hold ownership interests in the Funds and certain of their affiliates. After the closing of this offering, officers of our general partner will continue to devote significant time to the business of Memorial Resource. We cannot assure you that any conflicts that may arise between us and our unitholders, on the one hand, and Memorial Resource or the Funds, on the other hand, will be resolved in our favor. The existing positions held by these directors and officers may give rise to fiduciary duties that are in conflict with the fiduciary duties they owe to us. These officers and directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present them to us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our unitholders should be aware, please read “Business and Properties — Our Principal Business Relationships” and “Conflicts of Interest and Fiduciary Duties.”
 
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.
 
Our partnership agreement requires us to reimburse our general partner and its affiliates for all actual direct and indirect expenses they incur or actual payments they make on our behalf and all other expenses allocable to us or otherwise incurred by our general partner or its affiliates in connection with operating our


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business, including overhead allocated to our general partner by its affiliates, including Memorial Resource. These expenses include salary, bonus, incentive compensation (including equity 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 is entitled to determine in good faith the expenses that are allocable to us.
 
Prior to making distributions on our common units, we will reimburse our general partner and its affiliates for all such expenses. None of these reimbursements are capped. The reimbursements to Memorial Resource and our general partner will reduce the amount of cash otherwise available for distribution to our unitholders.
 
At the closing of this offering, we will enter into agreements with Memorial Resource and our general partner pursuant to which, among other things, we will make payments to Memorial Resource. These payments will be substantial and will reduce the amount of cash available for distribution to unitholders. These include the following:
 
  •  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).
 
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 general partner has the right (but not the obligation), at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (25%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following any reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash contribution per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
 
If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will be equal to that number of common units which would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right (if at all) to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued


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common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units and general partner units to our general partner in connection with resetting the target distribution levels. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”
 
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.
 
We have the right to redeem all of the units of any holder that is not an eligible citizen if we are or become subject to federal, state, or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property in which we have an interest because of the nationality, citizenship or other related status of any limited partner. Our general partner may require any limited partner or transferee to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common units and subordinated units of any holder that is not an eligible citizen or fails to furnish the requested information. Please read “The Partnership Agreement — Non-Citizen Assignees; Redemption.”
 
Common units held by persons who are non-taxpaying assignees will be subject to the possibility of redemption.
 
If our general partner determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on our ability to operate our assets or generate revenues from our assets, then our general partner may adopt such amendments to our partnership agreement as it determines are necessary or advisable to obtain proof of the U.S. federal income tax status of our limited partners (and their owners, to the extent relevant) and permit us to redeem the units 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. Please read “The Partnership Agreement — Non-Taxpaying Assignees; Redemption.”
 
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.
 
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner will be appointed by Memorial Resource. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
 
Our general partner will have control over all decisions related to our operations. Since, upon consummation of this offering, Memorial Resource will own our general partner, approximately 37.7% of our outstanding common units, and all of our subordinated units, the other unitholders will not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. Our


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partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. 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 held by Memorial Resource and its affiliates) after the subordination period has ended. 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, including our policy to distribute all of our available cash to our unitholders, without the approval of any other unitholder once the subordination period ends. Furthermore, the goals and objectives of Memorial Resource and its affiliates that hold our common units relating to us may not be consistent with those of a majority of the other unitholders. Please read “— 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.”
 
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.
 
Maintenance capital expenditures are those capital expenditures required to maintain our long-term asset base, including expenditures to replace our oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property. Our partnership agreement requires our general partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus in determining cash available for distribution from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by our conflicts committee at least once a year. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders from operating surplus will be lower than if actual maintenance capital expenditures had been deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term but will have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for the previous underestimation.
 
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.
 
Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:
 
  •  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 such decisions are made in good faith and with the honest belief that the decision was in our best interest;
 
  •  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 (i) on terms no less favorable to us than those generally being


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  provided to or available from unrelated third parties or (ii) 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.
 
By purchasing a common unit, a unitholder will become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”
 
Even if our unitholders are dissatisfied, they cannot remove our general partner without Memorial Resource’s consent.
 
The public unitholders will be unable initially to remove our general partner without Memorial Resource’s consent because Memorial Resource will own sufficient units upon completion of this offering to be able to prevent our general partner’s removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove our general partner. Upon consummation of this offering, Memorial Resource will own our general partner, approximately 37.7% of our outstanding common units (approximately 34.5% if the underwriters exercise their option to purchase additional common units in full), and all of our subordinated units.
 
Control of our general partner and its incentive distribution rights may be transferred to a third party without unitholder consent.
 
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Memorial Resource from transferring all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and thereby influence the decisions made by the board of directors and officers in a manner that may not be aligned with the interests of our unitholders.
 
In addition, our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.
 
We may not make cash distributions during periods when we record net income.
 
The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow, including cash from reserves established by our general partner, working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions to our unitholders during periods when we record net losses and may not make cash distributions to our unitholders during periods when we record net income.


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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 partnership agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:
 
  •  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.
 
Our partnership agreement restricts unitholders’ limited voting rights by providing that any common units held by a person, entity or group that owns 20% or more of any class of common units then outstanding (other than our general partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the board of directors of our general partner) cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.
 
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.
 
After the sale of the common units offered hereby, Memorial Resource will own approximately 37.7% of our outstanding common units and all of our subordinated units, which convert into common units at the end of the subordination period. Once our common units are publicly traded, the sale of these units, including common units issued upon the conversion of the subordinated units, in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.
 
Our general partner has a call right that may require common unitholders to sell their common units at an undesirable time or price.
 
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is the greater of (i) the highest cash price paid by either of our general partner or any of its affiliates for any common units purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those common units; and (ii) the average daily closing prices of our common units over the 20 days preceding the date three days before the date the notice is mailed. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders also may incur a tax liability upon a sale of their common units. Upon consummation of this offering, Memorial Resource will own approximately 37.7% of our outstanding common units and all of our subordinated units. For additional information about this call right, please read “The Partnership Agreement — Limited Call Right.”


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If we distribute cash from capital surplus, which is analogous to a return of capital, our minimum quarterly distribution will be reduced proportionately, and the distribution thresholds after which the incentive distribution rights entitle our general partner to an increased percentage of distributions will be proportionately decreased.
 
Our cash distributions will be characterized as coming from either operating surplus or capital surplus. Operating surplus is defined in our partnership agreement, and generally means amounts we receive from operating sources, such as sale of our oil and natural gas production, less operating expenditures, such as production costs and taxes, and less estimated average capital expenditures, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long term. Capital surplus is defined in our partnership agreement included in this prospectus as Appendix A, and generally would result from cash received from non-operating sources such as sales of properties and issuances of debt and equity interests. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and our general partner in proportion to their percentage interests in us, or 99.9% to our unitholders and 0.1% to our general partner, and will result in a decrease in our minimum quarterly distribution. For a more detailed description of operating surplus, capital surplus and the effect of distributions from capital surplus, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”
 
Our partnership agreement allows us to add to operating surplus $30.5 million. As a result, a portion of this amount, which is analogous to a return of capital, may be distributed to the general partner and its affiliates, as holders of incentive distribution rights, rather than to holders of common units as a return of capital.
 
Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.
 
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for our obligations as if it was a general partner if:
 
  •  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.
 
Please read “The Partnership Agreement — Limited Liability” for a discussion of the implications of the limitations of liability on a unitholder.
 
Our unitholders may have liability to repay distributions.
 
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.


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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.
 
Prior to this offering, there has been no public market for the common units. After this offering, there will be publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Our unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, a lack of liquidity would likely result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units. All of the 6,061,294 common units that are issued to affiliates of our general partner, or 37.7% of our outstanding common units, will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Each of the lock-up agreements with the underwriters may be waived by Citigroup Global Markets Inc. in its sole discretion. Sales by affiliates of our general partner of a substantial number of our common units in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to our general partner and its affiliates. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.
 
If our common unit price declines after the initial public offering, our unitholders could lose a significant part of their investment.
 
The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:
 
  •  changes in commodity prices;
 
  •  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.
 
In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.
 
Our unitholders will experience immediate and substantial dilution of $6.68 per unit.
 
The assumed initial offering price of $20.00 per common unit (the midpoint of the price range set forth on the cover of this prospectus) exceeds our pro forma net tangible book value after this offering of $13.32 per common unit. Based on the assumed initial offering price of $20.00 per common unit, our


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unitholders will incur immediate and substantial dilution of $6.68 per common unit. This dilution will occur primarily because the assets contributed by affiliates of our general partner are recorded, in accordance with GAAP at their historical cost, and not their fair value. The impact of such dilution would be magnified upon any conversion of the incentive distribution rights into common units. Please read “Dilution.”
 
We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions, and covenants in our new revolving credit facility may restrict our ability to make distributions.
 
Our partnership agreement allows us to borrow to make distributions. We may make short-term borrowings under our new revolving credit facility to make distributions. The primary purpose of these borrowings would be to mitigate the effects of short-term fluctuation in our working capital that would otherwise cause volatility in our quarter-to-quarter distributions.
 
The terms of our new revolving credit facility will restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility.
 
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production.
 
Our partnership agreement provides that we will distribute all of our available cash each quarter. As a result, we may be dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:
 
  •  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, NGLs and natural gas.
 
NASDAQ does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
 
We have applied to list our common units on NASDAQ. Because we will be a publicly traded limited partnership, NASDAQ does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of NASDAQ corporate governance requirements. Please read “Management — Management of Memorial Production Partners LP.”
 
Tax Risks to Unitholders
 
In addition to reading the following risk factors, prospective unitholders should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of our units.
 
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.
 
The anticipated after-tax economic benefit of an investment in the units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.


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Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.
 
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.
 
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax each year at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of any similar taxes by any other state may substantially reduce the cash available for distribution to our unitholders and, therefore, negatively impact the value of an investment in our units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation for state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.
 
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.
 
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial interpretation at any time. For example, the Obama Administration and members of Congress have recently considered substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.
 
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution and the target distribution levels may be adjusted to reflect the impact of that law on us.
 
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.
 
Both President Obama’s Proposed Fiscal Year 2012 Budget and the proposed American Jobs Act of 2011 include proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, or IDCs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted,


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how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.
 
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.
 
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
 
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.
 
Because our unitholders will be treated as partners to whom we will allocate taxable income, which could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
 
Tax gain or loss on the disposition of our units could be more or less than expected.
 
If our unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those units. Because distributions in excess of their allocable share of our total net taxable income decrease their tax basis in their units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation, depletion and IDC recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, if they sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale. Please read “Material Tax Consequences — Disposition of Common Units — Recognition of Gain or Loss.”
 
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.
 
Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts, or IRAs, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. Prospective unitholders who are tax-exempt entities or non-U.S. persons should consult their tax advisor before investing in our units.


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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.
 
Because we cannot match transferors and transferees of units and because of other reasons, we will adopt depreciation, depletion and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of units and could have a negative impact on the value of our units or result in audit adjustments to a unitholder’s tax returns. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election” for a further discussion of the effect of the depreciation, depletion and amortization positions we will adopt.
 
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.
 
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 use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Akin Gump Strauss Hauer & Feld LLP has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. Please read “Material Tax Consequences — Disposition of Common Units — Allocations Between Transferors and Transferees.”
 
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.
 
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Akin Gump Strauss Hauer & Feld LLP has not rendered an opinion regarding the treatment of a unitholder where units are loaned to a short seller to cover a short sale of units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
 
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.
 
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our


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assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between the general partner and certain of our unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions. Akin Gump Strauss Hauer & Feld LLP has not rendered an opinion with respect to whether our method for depreciating Section 743 adjustments is sustainable in certain cases.
 
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.
 
We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. Please read “Material Tax Consequences — Disposition of Common Units — Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.
 
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.
 
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future even if such unitholders do not live in those jurisdictions. Our unitholders likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We initially will own property and conduct business in Texas and Louisiana. Louisiana currently imposes a personal income tax on individuals. These states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. We may own property or conduct business in other states or foreign countries in the future. It is a unitholder’s responsibility to file all U.S. federal, state and local tax returns. Akin Gump Strauss Hauer & Feld LLP has not rendered an opinion on the state or local tax consequences of an investment in our units.


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USE OF PROCEEDS
 
We intend to use the estimated net proceeds of approximately $177 million from this offering, based upon the assumed initial public offering price of $20.00 per common unit (the midpoint of the price range set forth on the cover of this prospectus), after deducting underwriting discounts, structuring fees, fees and expenses associated with our new revolving credit facility and offering expenses, together with borrowings of approximately $130 million under our new revolving credit facility, as partial consideration (together with our issuance to Memorial Resource of 6,061,294 common units and 5,360,912 subordinated units) for the contribution by Memorial Resource and its subsidiaries (including our predecessor) of the Partnership Properties and to pay fees and expenses associated with such contribution, our new revolving credit facility and this offering.
 
The following table illustrates our use of the proceeds of this offering and our borrowings under our new revolving credit facility.
 
                     
Sources of Cash (In millions)     Uses of Cash (In millions)  
 
Gross proceeds from this offering(1)
  $ 200    
Cash consideration to Memorial Resource
  $ 307  
Borrowings under new revolving credit facility(1)
    130    
Underwriting discounts, structuring fees, fees and expenses associated with our new revolving credit facility and other offering and formation-related fees and expenses payable by us
    23  
                     
Total
  $ 330    
Total
  $ 330  
                     
 
 
(1) If the underwriters exercise their option to purchase additional common units in full, the gross proceeds would be $230 million and the amount borrowed under our new revolving credit facility would be approximately $100 million.
 
We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units to reduce outstanding borrowings under our new revolving credit facility. If the underwriters exercise in full their option to purchase additional common units, the ownership interest of the public unitholders will increase to 11,500,000 common units representing an aggregate 50.1% limited partner interest in us and the ownership interest of our general partner will increase to 22,945 general partner units representing a 0.1% general partner interest in us. Please read “Underwriting.”
 
Our estimates assume an initial public offering price of $20.00 per common unit (the midpoint of the price range set forth on the cover of this prospectus) and no exercise of the underwriters’ option to purchase additional common units. An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from this offering, after deducting underwriting discounts, to increase or decrease by $9.4 million and would increase or decrease the cash portion of the consideration to be paid to Memorial Resource for the Partnership Properties by the same amount. In addition, we may also increase or decrease the number of common units we are offering, which would result in a corresponding decrease or increase in the number of common units to be issued to Memorial Resource. Each increase of 1.0 million common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price to $21.00 per common unit, would increase net proceeds to us from this offering (and the cash portion of the consideration to be paid to Memorial Resource for the Partnership Properties) by approximately $28.9 million and decrease by 1.0 million the number of common units to be issued to Memorial Resource. Similarly, each decrease of 1.0 million common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price to $19.00 per common unit, would decrease the net proceeds to us from this offering (and the cash portion of the consideration to be paid to Memorial Resource for the Partnership Properties) by approximately $27.0 million and increase by 1.0 million the number of common units to be issued to Memorial Resource.


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CAPITALIZATION
 
The following table shows:
 
  •  the historical capitalization of our predecessor as of September 30, 2011; and
 
  •  our pro forma capitalization as of September 30, 2011, adjusted to reflect the issuance and sale of common units to the public at an assumed initial offering price of $20.00 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.”
 
We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Summary — Our Partnership Structure and Formation Transactions,” “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” For a description of the pro forma adjustments, please read our Unaudited Pro Forma Combined Financial Statements.
 
                 
    As of September 30, 2011  
          Pro Forma
 
    Our
    Memorial
 
    Predecessor
    Production
 
    Historical     Partners LP  
    (In thousands)  
 
Long-term debt(1)
  $ 203,228     $ 130,000  
Partners’ capital/net equity:
               
Predecessor partners’ capital
    229,436        
Common units held by purchasers in this offering
          178,600  
Common units held by Memorial Resource
          56,704  
Subordinated units held by Memorial Resource
          50,152  
General partner interest
          200  
                 
Total partners’ capital/net equity(2)
    229,436       285,656  
                 
Total capitalization
  $ 432,664     $ 415,656  
                 
 
 
(1) We intend to enter into a $1.0 billion revolving credit facility, approximately $300 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 million under our new revolving credit facility, we will have approximately $170 million of borrowing capacity. We do not anticipate having any outstanding letters of credit against our borrowing capacity at the closing of this offering. 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 (and the cash portion of the consideration to be paid to Memorial Resource for the Partnership Properties) by approximately $9.4 million and would change our total partners’ capital by approximately $9.4 million, assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same. Each increase of 1.0 million common units offered by us, together with a concurrent $1.00 increase in the assumed initial public offering price to $21.00 per common unit, would increase the net proceeds (and the cash portion of the consideration to be paid to Memorial Resource for the Partnership Properties) by approximately $28.9 million, and would change our total partners’ capital by approximately $28.9 million and decrease by 1.0 million the number of common units to be issued to Memorial Resource. Similarly, each decrease of 1.0 million common units offered by us, together with a concurrent $1.00 decrease in the assumed initial public offering price to $19.00 per common unit, would decrease the net proceeds (and the cash portion of the consideration to be paid to Memorial Resource for the Partnership Properties) by approximately $27.0 million, and would change our total partners’ capital by approximately $27.0 million and increase by 1.0 million the number of common units to be issued to Memorial Resource.
 
This table does not reflect the issuance of up to an additional 1,500,000 common units that may be sold to the underwriters upon exercise of their option to purchase additional common units.


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DILUTION
 
Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma as adjusted net tangible book value per unit after this offering. Net tangible book value is our total tangible assets less total liabilities. Assuming an initial offering price of $20.00 per common unit (the midpoint of the price range set forth on the cover of this prospectus), on a pro forma as adjusted basis as of September 30, 2011, after giving effect to the transactions described under “Summary — Our Partnership Structure and Formation Transactions,” including this offering of common units and the application of the related net proceeds and assuming the underwriters’ option to purchase additional common units is not exercised, our pro forma as adjusted net tangible book value was $285.7 million, or $13.32 per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for accounting purposes, as illustrated in the following table:
 
                 
Assumed initial offering price per common unit
          $ 20.00  
Pro forma as adjusted net tangible book value per unit before this offering(1)
  $ 19.16          
Decrease in net tangible book value per unit attributable to purchasers in this offering
    (5.84 )        
                 
Less: Pro forma as adjusted net tangible book value per unit after this offering(2)
            13.32  
                 
Immediate dilution in net tangible book value per unit to purchasers in this offering(3)
          $ 6.68  
                 
 
 
(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 (6,061,294 common units and 5,360,912 subordinated units) to be issued to Memorial Resource as partial consideration for their contribution of the Partnership Properties to us and the 21,444 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 (16,061,294 common units, 5,360,912 subordinated units, and 21,444 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 $7.68 or $5.68, 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.
 
The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates, including Memorial Resource, in respect of their units and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:
 
                                 
    Units Acquired   Total Consideration
    Number   Percent   $   Percent
            (In millions)    
 
General partner and its affiliates(1)(2)
    11,443,650       53.4 %   $ 219.3       55.3 %
Purchasers in the offering(3)
    10,000,000       46.6 %     177.0       44.7 %
                                 
Total
    21,443,650       100.0 %   $ 396.3       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 6,061,294 common units, 5,360,912 subordinated units, and 21,444 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 September 30, 2011 and does not include the $110.7 million cash distribution to be made to Memorial Resource as partial consideration for their contribution of the Partnership Properties to us.
 
(3) Total consideration is after deducting underwriting discounts and estimated offering expenses.


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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 December 31, 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 nine months ended September 30, 2011 and 2010, and our unaudited pro forma combined financial statements for the year ended December 31, 2010 and the nine months ended September 30, 2011, all included elsewhere in this prospectus.
 
General
 
Rationale for Our Cash Distribution Policy
 
Our partnership agreement requires us to distribute all of our available cash on a quarterly basis. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures, operational needs and certain future distributions, including cash from borrowings. We intend to fund any acquisitions and growth capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it. Also, because we are not subject to an entity-level federal income tax, we will have more cash to distribute to our unitholders than would be the case if we were subject to federal income tax.
 
Restrictions and Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy
 
There is no guarantee that unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or distributions at any other rate except as provided in our partnership agreement. Our distribution policy is subject to certain restrictions and may be changed at any time, including:
 
  •  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 maintenance capital expenditures. Over a longer


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  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 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, and Memorial Resource will be entitled for such reimbursement under the omnibus agreement. 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 37.7% 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 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


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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 cash basket equal to $30.5 million and working capital borrowings. Consequently, it is possible that distributions from operating surplus may represent a return of capital. For example, the $30.5 million cash basket would allow us to distribute as operating surplus cash proceeds we receive in the future from non-operating sources such as asset 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 make distributions to our unitholders depends on the performance of our operating subsidiaries and its ability to distribute cash to us. The ability of our operating subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.
 
Our Ability to Grow Depends on Our Ability to Access External Growth Capital
 
Our partnership agreement requires us to distribute all of our available cash to unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity interests, rather than cash reserves established by our general partner, to fund our growth capital expenditures and any acquisitions. To the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand their ongoing operations. To the extent we issue additional units in connection with any growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our quarterly per unit distribution level. There are no limitations in our partnership agreement or our new revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
 
Our Minimum Quarterly Distribution
 
Upon completion of this offering, the board of directors of our general partner will establish a minimum quarterly distribution of $0.4750 per unit per whole quarter, or $1.90 per unit per year on an annualized basis, to be paid no later than 45 days after the end of each fiscal quarter beginning with the quarter ending December 31, 2011. This equates to an aggregate cash distribution of approximately $10.2 million per quarter or $40.7 million per year, in each case based on the number of common units, subordinated units and general partner units outstanding immediately after completion of this offering, but excluding 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. If the underwriters exercise their option to purchase additional common units in full, 17,561,294 common units, 5,360,912 subordinated units and 21,444 general partner units will be outstanding, which equates to an aggregate cash distribution of approximately $10.9 million per quarter or $43.6 million per year. Our ability to make cash distributions at the minimum quarterly distribution will be subject to the factors described above under the caption “— General — Restrictions and Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”


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As of the date of this offering, our general partner will be entitled to 0.1% of all distributions of available cash that we make prior to our liquidation. Our general partner’s initial 0.1% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 0.1% general partner interest. Our general partner is not obligated to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner will also hold the incentive distribution rights, which entitle the holder to additional increasing percentages, up to a maximum of 24.9%, of the cash we distribute in excess of $0.54625 per common unit per quarter.
 
The table below sets forth the assumed number of outstanding common (assuming no exercise and full exercise of the underwriters’ option to purchase additional common units), subordinated and general partner units upon the closing of this offering and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our minimum quarterly distribution of $0.4750 per unit per quarter, or $1.90 per unit on an annualized basis.
 
                                                 
    No Exercise of the Underwriters’
    Full Exercise of the Underwriters’
 
    Option to Purchase Additional Common Units     Option to Purchase Additional Common Units  
          Distributions           Distributions  
    Number of
    One
    Four
    Number of
    One
    Four
 
    Units     Quarter     Quarters     Units     Quarter     Quarters  
 
Common units held by purchasers in this offering(1)
    10,000,000     $ 4,750,000     $ 19,000,000       11,500,000     $ 5,462,500     $ 21,850,000  
Common units held by Memorial Resource and its affiliates(1)
    6,061,294       2,879,115       11,516,458       6,061,294       2,879,115       11,516.458  
Subordinated units
    5,360,912       2,546,433       10,185,734       5,360,912       2,546,433       10,185,734  
General partner units
    21,444       10,186       40,743       22,945       10,899       43,596  
                                                 
Total
    21,443,650     $ 10,185,734     $ 40,742,935       22,945,151     $ 10,898,947     $ 43,595,788  
                                                 
 
 
(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.
 
If the minimum quarterly distribution on our common units is not paid with respect to any quarter, the common unitholders will not be entitled to receive such payments in the future except that, during the subordination period, to the extent we distribute cash in any future quarter in excess of the amount necessary to make cash distributions at the minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any of these arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period.”
 
We do not have a legal obligation to pay the minimum quarterly distribution or distributions at any other rate except as provided in our partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of expenses and the amount of reserves our general partner determines is necessary or appropriate to provide for the prudent conduct of our business (including payments to our general partner for reimbursement of expenses it incurs on our behalf), to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the next four quarters. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions — Distributions of Available Cash — Definition of Available Cash.”
 
Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or imposed at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above; however, our partnership agreement provides that our general partner is


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entitled to make the determinations described above without regard to any standard other than the requirement to act in good faith. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must have an honest belief that the determination is in our best interests. Please read “Conflicts of Interest and Fiduciary Duties.”
 
Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuation based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. Our partnership agreement, including provisions contained therein requiring us to make cash distributions, may be amended by a vote of the holders of a majority of our common units. Upon consummation of this offering, Memorial Resource will own our general partner, approximately 37.7% 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 a controlling portion of its equity interests in our general partner or its common units, Memorial Resource will have the ability to amend our partnership agreement without the approval of any other unitholders once the subordination period ends.
 
We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the first day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. For our initial quarterly distribution, we will adjust the quarterly distribution for the period from the closing of this offering through December 31, 2011 based on the actual length of the period. We expect to pay this initial quarterly cash distribution on or before February 14, 2012.
 
In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our minimum quarterly distribution of $0.4750 per unit each quarter for the four quarters ending December 31, 2012. In those sections, we present two tables, consisting of:
 
  •  “Unaudited Pro Forma Available Cash for the Year Ended December 31, 2010 and Twelve Months Ended September 30, 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 September 30, 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 December 31, 2012.
 
Unaudited Pro Forma Available Cash for the Year Ended December 31, 2010 and Twelve Months Ended September 30, 2011
 
If we had completed the formation transactions contemplated in this prospectus and the acquisition of all of the Partnership Properties on January 1, 2010, our unaudited pro forma available cash generated during the year ended December 31, 2010 would have been approximately $47.3 million. Assuming the underwriters do not exercise their option to purchase additional common units, this amount would have been sufficient to make a cash distribution for the year ended December 31, 2010 at the minimum quarterly distribution of $0.4750 per unit per quarter (or $1.90 per unit on an annualized basis) on all of our common units, general partner units and subordinated units. Assuming the underwriters exercise in full their option to purchase additional common units, this amount would have been sufficient to make a cash distribution for the year ended December 31, 2010 at the minimum quarterly distribution of $0.4750 per unit per quarter (or $1.90 per unit on an annualized basis) on all of our common units, general partner units and subordinated units. The number of outstanding common and subordinated units on which we have based such belief does not include


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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.
 
If we had completed the formation transactions contemplated in this prospectus and the acquisition of all of the Partnership Properties on October 1, 2010, our unaudited pro forma available cash generated during the twelve months ended September 30, 2011 would have been approximately $39.6 million. Pro forma available cash for the twelve months ended September 30, 2011 was negatively impacted by non-routine items that increased lease operating expense by approximately $2.1 million. Assuming the underwriters do not exercise their option to purchase additional common units, this amount would have been sufficient to make an average cash distribution for the twelve months ended September 30, 2011 at the minimum quarterly distribution of $0.4750 per unit per quarter (or $1.90 per unit on an annualized basis) on all of our common units and general partner units and a quarterly distribution of $0.42 per unit on our subordinated units. Assuming the underwriters exercise in full their option to purchase additional common units, this amount would have been sufficient to make an average cash distribution for the twelve months ended September 30, 2011 at the minimum quarterly distribution of $0.4750 per unit per quarter (or $1.90 per unit on an annualized basis) on all of our common units and general partner units and an average quarterly distribution of $0.29 per unit on all of our subordinated units. The number of outstanding common and subordinated units on which we have based such belief 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. We have not calculated available cash on a pro forma quarter-by-quarter basis for the year ended December 31, 2010 or the twelve months ended September 30, 2011 to determine if we would have generated available cash sufficient to pay the minimum quarterly distribution for each quarter during those periods. As a private company, our predecessor was not required to prepare quarterly financial information for all periods and we have not prepared quarterly financial information for all periods shown in this prospectus. In addition, a significant portion of the Partnership Properties were acquired during 2011 and we have not been provided by the sellers, and thus do not have access to, quarter-by-quarter financial information with respect to those assets prior to our acquisition. Accordingly, we cannot and have not used or relied upon quarter-by-quarter financial information to determine if we would have generated available cash sufficient to pay the minimum quarterly distribution for each quarter during those periods. Rather, we have based our determination whether we would have generated sufficient available cash to pay the minimum quarterly distribution for each quarter during the applicable period on financial information for the entire four quarter period.
 
Unaudited pro forma available cash also includes general and administrative expenses, which were calculated on a different basis as compared to historical periods. These general and administrative expenses are expected to total $5.0 million annually and consist of $2.5 million of general and administrative expenses we expect to be allocated to us by Memorial Resource during the twelve months ending December 31, 2012 as well as $2.5 million of general and administrative expenses we expect to incur as a result of becoming a publicly traded partnership. Our general partner is entitled to determine in good faith the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement, and Memorial Resource is entitled to reimbursement under the omnibus agreement. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement.” We will incur general and administrative expenses related to being a publicly traded partnership, which will include expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on NASDAQ; independent auditor fees; legal fees; investor relations expenses; and registrar and transfer agent fees. These expenses are not reflected in the historical combined financial statements of our predecessor or our pro forma combined financial statements.
 
We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus and the acquisition of all of our properties actually been completed as of the dates presented. In addition, cash available to pay distributions is primarily a cash accounting concept, while our unaudited pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of unaudited pro forma available cash only as a general


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indication of the amount of cash available to pay distributions that we might have generated had we been formed in an earlier period.
 
The forecast has been prepared by and is the responsibility of management. Our forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending December 31, 2012. While the assumptions disclosed in this prospectus are not all-inclusive, the assumptions listed below are those that we believe are material to our forecasted results of operations and any assumptions not discussed below were not deemed to be material. We believe we have a reasonable objective basis for these assumptions; however, there will likely be differences between our forecast and the actual results and those differences could be material. If the forecast is not achieved, we may not be able to pay cash distributions on our common units at the minimum quarterly distribution rate or at all.
 
The following table illustrates, on an unaudited pro forma basis, for the year ended December 31, 2010 and the twelve months ended September 30, 2011, the amount of available cash that would have been available for distribution to our unitholders, assuming that the formation transactions (including the acquisition of all of the Partnership Properties) and this offering had been consummated on January 1, 2010 and October 1, 2010, respectively and that the underwriters did not exercise their option to purchase additional common units. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.
 
Memorial Production Partners LP
Unaudited Pro Forma Cash Available for Distribution
 
                 
    Pro Forma  
    Year Ended
    Twelve Months Ended
 
    December 31, 2010     September 30, 2011  
    (In thousands, except per unit data)  
 
Net income (loss)
  $ 12,563     $ 79,180  
Interest expense
    4,105       4,105  
Income tax expense
    225       347  
Depreciation, depletion and amortization
    34,772       29,818  
Impairment
    9,509       4,461  
Accretion of asset retirement obligations
    1,072       1,085  
Unrealized (gains) losses on derivative instruments
    (2,970 )     (5,325 )
Acquisition related costs
    890       811  
(Gain) loss on sale of properties
          (62,020 )
Unit-based compensation expense
           
Exploration costs
    36       36  
                 
Adjusted EBITDA(1)
  $ 60,202     $ 52,498  
Less:
               
Cash interest expense(2)
  $ 3,705     $ 3,705  
Estimated average maintenance capital expenditures(3)
    9,200       9,200  
                 
Pro forma available cash(4)
  $ 47,297     $ 39,593  
                 
Pro forma annualized distributions per unit(5)
  $ 1.90     $ 1.90  
Pro forma estimated annual cash distributions:
               
Distributions on common units held by purchasers in this offering(5)
  $ 19,000     $ 19,000  
Distributions on common units held by Memorial Resource and its affiliates(5)
    11,516       11,516  
Distributions on subordinated units(5)
    10,186       10,186  
Distributions on general partner units(5)
    41       41  
                 
Total estimated annual cash distributions(5)
  $ 40,743     $ 40,743  
                 
Excess (Shortfall)(5)
  $ 6,554     $ (1,150 )
                 
Percent of minimum quarterly distributions payable to common unitholders
    100 %     100 %
Percent of minimum quarterly distributions payable to subordinated unitholders
    100 %     88.7 %


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(1) Adjusted EBITDA is defined in “Summary — Non-GAAP Financial Measure.”
 
(2) In connection with this offering, we intend to enter into a new $1.0 billion revolving credit facility under which we expect to incur approximately $130 million of borrowings upon the closing of this offering. The pro forma cash interest expense is based on $130 million of borrowings at an assumed weighted-average rate of 2.85%. 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.
 
(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. Our estimates accounted for our targeted average net production from our assets of 49 MMcfe/d through December 31, 2015, our decline rate for our existing proved developed producing reserves of approximately 9% and the amount of capital expenditures required annually to be expended on reserve development to maintain the reserve base and replace the production lost to depletion. To the extent capital expenditures exceed our targeted annual maintenance capital expenditure of $9.2 million, such expenditures would be considered growth capital expenditures and we would expect an increase in production and cash flows accordingly.
 
(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 Forma  
    Year Ended
    Twelve Months Ended
 
    December 31, 2010     September 30, 2011  
    (In thousands, except per unit data)  
 
Pro forma annualized distributions per unit
  $ 1.90     $ 1.90  
Pro forma estimated annual cash distributions:
               
Distributions on common units held by purchasers in this offering
  $ 21,850     $ 21,850  
Distributions on common units held by Memorial Resource and its affiliates
    11,516       11,516  
Distributions on subordinated units
    10,186       10,186  
Distributions on general partner units
    44       44  
                 
Total estimated annual cash distributions
  $ 43,596     $ 43,596  
                 
Excess (Shortfall)
  $ 3,701     $ (4,003 )
                 
 
Estimated Adjusted EBITDA for the Twelve Months Ending December 31, 2012
 
The cumulative amount that we would distribute for the twelve months ending December 31, 2012, if we made distributions on all our common units, subordinated units and general partner units at the minimum quarterly distribution rate of $0.4750 per unit during that period, would be $40.7 million if the underwriters do not exercise their option to purchase additional common units and $43.6 million if the underwriters exercise in full their option to purchase additional common units. Based upon the assumptions and considerations set forth in “— Assumptions and Considerations,” in order to fund distributions on all our common units, subordinated units and general partner units at the minimum quarterly distribution rate for the twelve months ending December 31, 2012, we estimate that our minimum Adjusted EBITDA for that period must be at least $53.6 million if the underwriters do not exercise their option to purchase additional common units and at least $55.8 million if the underwriters exercise in full their option to purchase additional common units. The number of outstanding common and subordinated units on which we have based such estimates does not


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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.
 
Based on the assumptions set forth in “— Assumptions and Considerations,” and as set forth in the table below, we believe that we will be able to generate approximately $61.8 million in Adjusted EBITDA during the twelve months ending December 31, 2012, which amount we refer to as our “estimated Adjusted EBITDA.” We can give you no assurance, however, that we will generate this amount of Adjusted EBITDA during that period. There will likely be differences between our estimated Adjusted EBITDA and our actual results for the twelve months ending December 31, 2012, and those differences could be material. In addition, Adjusted EBITDA may not represent actual cash generated during an applicable period because of, among other things, timing differences between the incurrence and actual payment of accounts payable and accounts receivable. If the amount of Adjusted EBITDA that we actually generate during the twelve months ending December 31, 2012 is less than our estimated Adjusted EBITDA, we may not be able to pay the minimum quarterly distribution on all of our units.
 
Our management has prepared the prospective financial information that is the basis of our estimated Adjusted EBITDA below to substantiate our belief that we will have sufficient cash to pay the minimum quarterly distribution on all outstanding common, subordinated and general partner units for the twelve months ending December 31, 2012. This prospective financial information is a forward-looking statement and should be read together with the historical and unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” This prospective financial information was not prepared with a view toward complying with the published guidelines of the SEC or the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of our management’s knowledge and belief, the assumptions and considerations on which we base our belief that we can generate sufficient Adjusted EBITDA to pay the minimum quarterly distribution to all of our common unitholders and subordinated unitholders, as well as in respect of our general partner units, for the twelve months ending December 31, 2012. However, this prospective financial information is not fact and may not be necessarily indicative of our actual results of operations, and readers of this prospectus are cautioned not to place undue reliance on this prospective financial information. Please read “— Assumptions and Considerations.”
 
The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Neither KPMG nor any other independent accountant has compiled or performed any procedures with respect to the accompanying prospective financial information and, accordingly, KPMG and any other accounting firm do not express an opinion or any other form of assurance with respect thereto. The KPMG and the other independent auditor reports included in the registration statement relate to historical financial information. Those reports do not extend to the prospective financial information and should not be read to do so.
 
When considering this prospective financial information, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate the estimated Adjusted EBITDA sufficient to pay the minimum quarterly distributions to holders of our common, subordinated and general partner units for the twelve months ending December 31, 2012.
 
We do not undertake any obligation to release publicly the results of any future revisions we may make to this prospective financial information or to update this prospective financial information to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.
 
As a result of the factors described in “— Our Estimated Adjusted EBITDA” and “— Assumptions and Considerations,” we believe we will be able to pay cash distributions at the minimum quarterly distribution of $0.4750 per unit on all outstanding common, subordinated and general partner units for each full calendar


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quarter in the twelve months ending December 31, 2012. The number of outstanding common units on which we have based such belief 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.
 
Our Estimated Adjusted EBITDA
 
Adjusted EBITDA is a significant financial metric that will be used by our management to indicate (prior to the establishment of any reserves by the board of directors of our general partner) the cash distributions we expect to pay to our unitholders. Specifically, we intend to use this financial measure to assist us in determining whether we are generating operating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. As used in this prospectus, the term “Adjusted EBITDA” means the sum of net income (loss) adjusted by the following to the extent included in calculating such net income (loss):
 
  •  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;
 
  •  Acquisition related 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.


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Memorial Production Partners LP
Estimated Adjusted EBITDA
Assuming No Exercise of the Underwriters’ Option to Purchase Additional Common Units
 
                                         
    Forecasted  
    Three Months Ending     Twelve Months Ending  
    March 31, 2012     June 30, 2012     September 30, 2012     December 31, 2012     December 31, 2012  
    (In millions, except for per unit amounts)  
 
Operating revenue and realized commodity derivative gains (losses)(1)
  $ 22.8     $ 23.1     $ 23.3     $ 23.7     $ 93.0  
Less:
                                       
Lease operating expenses
    4.6       4.6       4.6       4.6       18.3  
Production and ad valorem taxes
    1.9       1.9       2.0       2.0       7.9  
General and administrative expenses
    1.3       1.3       1.3       1.3       5.0  
Depreciation, depletion and amortization
    7.8       7.9       8.0       8.0       31.7  
Interest expense
    0.9       0.9       0.9       0.9       3.7  
                                         
Net income excluding unrealized derivative gains (losses)
  $ 6.3     $ 6.5     $ 6.6     $ 7.0     $ 26.3  
Adjustments to reconcile net income excluding unrealized derivative gains (losses) to estimated Adjusted EBITDA:
                                       
Add:
                                       
Depreciation, depletion and amortization
  $ 7.8     $ 7.9     $ 8.0     $ 8.0     $ 31.7  
Interest expense
    0.9       0.9       0.9       0.9       3.7  
                                         
Estimated Adjusted EBITDA
  $ 15.1     $ 15.3     $ 15.5     $ 15.9     $ 61.8  
Adjustments to reconcile estimated Adjusted EBITDA to cash available for distribution:
                                       
Less:
                                       
Cash interest expense(2)
  $ 0.9     $ 0.9     $ 0.9     $ 0.9     $ 3.7  
Estimated average maintenance capital expenditures(3)
    2.3       2.3       2.3       2.3       9.2  
                                         
Estimated cash available for distribution
  $ 11.8     $ 12.1     $ 12.3     $ 12.7     $ 48.9  
Annualized minimum quarterly distribution per unit
  $ 0.4750     $ 0.4750     $ 0.4750     $ 0.4750     $ 1.90  
Estimated annual cash distributions:
                                       
Distributions on common units held by purchasers in this offering
  $ 4.8     $ 4.8     $ 4.8     $ 4.8     $ 19.0  
Distributions on common units held by Memorial Resource and its affiliates
    2.9       2.9       2.9       2.9       11.5  
Distributions on subordinated units
    2.5       2.5       2.5       2.5       10.2  
Distributions on general partner units
    *       *       *       *       *  
                                         
Total estimated annual cash distributions
  $ 10.2     $ 10.2     $ 10.2     $ 10.2     $ 40.7  
                                         
Excess cash available for distribution
  $ 1.7     $ 1.9     $ 2.1     $ 2.5     $ 8.1  
                                         
Minimum estimated Adjusted EBITDA:
                                       
Estimated Adjusted EBITDA
  $ 15.1     $ 15.3     $ 15.5     $ 15.9     $ 61.8  
Less:
                                       
Excess cash available for distributions(4)
    1.7       1.9       2.1       2.5       8.1  
                                         
Minimum estimated Adjusted EBITDA
  $ 13.4     $ 13.4     $ 13.4     $ 13.4     $ 53.6  
                                         
 
 
* Distribution represents less than $0.1 million.


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Memorial Production Partners LP
Estimated Adjusted EBITDA
Assuming Full Exercise of the Underwriters’ Option to Purchase Additional Common Units
 
                                         
    Forecasted  
    Three Months Ending     Twelve Months Ending  
    March 31, 2012     June 30, 2012     September 30, 2012     December 31, 2012     December 31, 2012  
    (In millions, except for per unit amounts)  
 
Operating revenue and realized commodity derivative gains (losses)(1)
  $ 22.8     $ 23.1     $ 23.3     $ 23.7     $ 93.0  
Less:
                                       
Lease operating expenses
    4.6       4.6       4.6       4.6       18.3  
Production and ad valorem taxes
    1.9       1.9       2.0       2.0       7.9  
General and administrative expenses
    1.3       1.3       1.3       1.3       5.0  
Depreciation, depletion and amortization
    7.8       7.9       8.0       8.0       31.7  
Interest expense
    0.8       0.8       0.8       0.8       3.1  
                                         
Net income excluding unrealized derivative gains (losses)
  $ 6.5     $ 6.6     $ 6.8     $ 7.1     $ 27.0  
Adjustments to reconcile net income excluding unrealized derivative gains (losses) to estimated Adjusted EBITDA:
                                       
Add:
                                       
Depreciation, depletion and amortization
  $ 7.8     $ 7.9     $ 8.0     $ 8.0     $ 31.7  
Interest expense
    0.8       0.8       0.8       0.8       3.1  
                                         
Estimated Adjusted EBITDA
  $ 15.1     $ 15.3     $ 15.5     $ 15.9     $ 61.8  
Adjustments to reconcile estimated Adjusted EBITDA to cash available for distribution:
                                       
Less:
                                       
Cash interest expense(2)
  $ 0.8     $ 0.8     $ 0.8     $ 0.8     $ 3.1  
Estimated average maintenance capital expenditures(3)
    2.3       2.3       2.3       2.3       9.2  
                                         
Estimated cash available for distribution
  $ 12.0     $ 12.3     $ 12.5     $ 12.8     $ 49.5  
Annualized minimum quarterly distribution per unit
  $ 0.4750     $ 0.4750     $ 0.4750     $ 0.4750     $ 1.90  
Estimated annual cash distributions:
                                       
Distributions on common units held by purchasers in this offering
  $ 5.5     $ 5.5     $ 5.5     $ 5.5     $ 21.9  
Distributions on common units held by Memorial Resource and its affiliates
    2.9       2.9       2.9       2.9       11.5  
Distributions on subordinated units
    2.5       2.5       2.5       2.5       10.2  
Distributions on general partner units
    *       *       *       *       *  
                                         
Total estimated annual cash distributions
  $ 10.9     $ 10.9     $ 10.9     $ 10.9     $ 43.6  
                                         
Excess cash available for distribution
  $ 1.1     $ 1.4     $ 1.6     $ 1.9     $ 5.9  
                                         
Minimum estimated Adjusted EBITDA:
                                       
Estimated Adjusted EBITDA
  $ 15.1     $ 15.3     $ 15.5     $ 15.9     $ 61.8  
Less:
                                       
Excess cash available for distributions(4)
    1.1       1.4       1.6       1.9       5.9  
                                         
Minimum estimated Adjusted EBITDA
  $ 14.0     $ 14.0     $ 14.0     $ 13.9     $ 55.8  
                                         
 
 
* Distribution represents less than $0.1 million.


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(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 $1.0 billion revolving credit facility under which we expect to incur approximately $130 million of borrowings upon the closing of this offering. The pro forma cash interest expense is based on $130 million of borrowings at an assumed weighted-average rate of 3.13%. If the interest rate used to calculate this interest were 1% higher or lower, our annual cash interest expense would increase or decrease by $1.2 million.
 
(3) In calculating the estimated cash available for distribution, we have included our estimated maintenance capital expenditures for the twelve months ending December 31, 2012. To maintain our targeted average net production from our assets of 49 MMcfe/d through December 31, 2015, we expect to incur approximately $9.2 million of annual capital expenditures for the twelve months ending December 31, 2012 based on our reserve reports as of December 31, 2010.
 
(4) We intend to retain any excess cash to repay indebtedness or for other general partnership purposes.
 
Assumptions and Considerations
 
Based upon the specific assumptions outlined below with respect to the twelve months ending December 31, 2012, we expect to generate estimated Adjusted EBITDA sufficient to establish reserves for capital expenditures and to pay the minimum quarterly distribution on all common, subordinated and general partner units for the twelve months ending December 31, 2012.
 
While we believe that these assumptions are reasonable in light of management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions do not materialize, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay quarterly cash distributions equal to our minimum quarterly distribution (absent borrowings under our new revolving credit facility), or any amount, on all common, subordinated and general partner units, in which event the market price of our common units may decline substantially. We are unlikely to be able to sustain our minimum quarterly distribution without making capital expenditures that maintain our asset base. Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient cash expenditures to maintain our asset base, we will be unable to pay distributions at the then-current level from cash generated from operations and would therefore expect to reduce our distributions. We intend to pay for maintenance capital expenditures from operating cash flow, and we expect to primarily rely upon external financing sources, including commercial bank borrowings and the issuance of debt and equity interests, rather than cash reserves established by our general partner, to fund our growth capital expenditures and any acquisitions. In addition, decreases in commodity prices from current levels will adversely affect our ability to pay distributions. When reading this section, you should keep in mind the risk factors and other cautionary statements described under “Risk Factors” and “Forward-Looking Statements.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.


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Operations and Revenue
 
Production.  The following table sets forth information regarding net production of oil and natural gas on a pro forma basis for the year ended December 31, 2010 and the twelve months ended September 30, 2011, and on a forecasted basis for the twelve months ending December 31, 2012:
 
                         
                Forecasted
 
    Pro Forma Year
    Pro Forma
    Twelve Months
 
    Ended
    Twelve Months
    Ending
 
    December 31,
    Ended
    December 31,
 
    2010     September 30, 2011     2012  
          (Unaudited)        
 
Annual Production:
                       
Oil (MBbl)
    107       99       101  
NGLs (MBbl)
    272       224       188  
Natural Gas (MMcf)
    16,713       16,142       16,339  
                         
Total (MMcfe)
    18,985       18,083       18,073  
Average Net Production:
                       
Oil (MBbl/d)
    0.3       0.3       0.3  
NGLs (MBbl/d)
    0.8       0.6       0.5  
Natural Gas (MMcf/d)
    45.8       44.2       44.6  
                         
Total (MMcfe/d)
    52.0       49.5       49.4  
 
We estimate that our oil and natural gas production for the twelve months ending December 31, 2012 will be 18,073 MMcfe as compared to 18,985 and 18,083 MMcfe, respectively, on a pro forma basis for the year ended December 31, 2010 and the twelve months ended September 30, 2011. We intend to maintain our forecasted production level of 49 MMcfe/d for the twelve months ending December 31, 2012 over the long term with cash generated from operations.


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Prices.  The table below illustrates the relationship between average oil and natural gas realized sales prices and the average NYMEX prices on a pro forma basis for the year ended December 31, 2010 and the twelve months ended September 30, 2011 and on a forecasted basis for the twelve months ending December 31, 2012:
 
                         
                Forecasted
 
    Pro Forma
    Pro Forma
    Twelve Months
 
    Year Ended
    Twelve Months
    Ending
 
    December 31,
    Ended
    December 31,
 
    2010     September 30, 2011     2012  
    (Unaudited)  
 
Average oil sales prices:
                       
NYMEX-WTI oil price per Bbl
  $ 79.59     $ 91.28     $ 92.72  
Differential to NYMEX-WTI oil per Bbl
  $ (5.24 )   $ (3.47 )   $ (4.28 )
                         
Realized oil sales price per Bbl (excluding cash settlements of derivatives)
  $ 74.35     $ 87.81     $ 88.44  
Realized oil sales price per Bbl (including cash settlements of derivatives)(1)(2)
  $ 74.35     $ 87.81     $ 88.40  
Average natural gas liquids sales prices:
                       
NYMEX-WTI oil price per Bbl
  $ 79.59     $ 91.28     $ 92.72  
Differential to NYMEX-WTI oil price per Bbl
  $ (42.18 )   $ (44.71 )   $ (49.87 )
                         
Realized natural gas liquids sales price per Bbl (excluding cash settlements of derivatives)(1)(2)
  $ 37.41     $ 46.57     $ 42.85  
Realized natural gas liquids sales price per Bbl (including cash settlements of derivatives)(1)(2)
  $ 37.41     $ 46.57     $ 42.93  
Average natural gas sales prices:
                       
NYMEX-Henry Hub natural gas price per MMBtu
  $ 4.39     $ 4.16     $ 4.15  
Differential to NYMEX-Henry Hub natural gas
  $ (0.22 )   $ (0.04 )   $ (0.05 )
                         
Realized natural gas sales price per Mcf (excluding cash settlements of derivatives)
  $ 4.17     $ 4.12     $ 4.10  
Realized natural gas sales price per Mcf (including cash settlements of derivatives)(1)(2)
  $ 4.17     $ 4.12     $ 4.65  
                         
Total combined price (per Mcfe, excluding cash settlements of derivatives)
  $ 4.62     $ 4.74     $ 4.64  
Total combined price (per Mcfe, including cash settlements of derivatives)(1)(2)
  $ 4.62     $ 4.74     $ 5.14  
 
 
(1) Average NYMEX futures prices for 2012 as reported on October 28, 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 62% of our total forecasted production for the twelve months ending December 31, 2012.


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Price Differentials.  As is typical in the oil and natural gas industry and as reflected in our reserve reports, we report our natural gas production and estimated reserves in Mcf, while we sell our natural gas production and enter into derivative contracts that measure natural gas in MMBtu, a measure of the heating capacity of natural gas. The following table presents the average Btu content for our natural gas production by operating area:
 
         
Operating Area
  MMBtu per Mcf
 
South Texas
    1.045  
East Texas
    1.026  
         
Weighted Average
    1.039  
 
To the extent the Btu content for our natural gas production is above 1.000 MMBtu per Mcf, we will receive a price premium relative to the NYMEX-Henry Hub price.
 
However, our natural gas production has historically sold at a negative basis differential from the NYMEX-Henry Hub price primarily due to the distance of the production attributable to our operating areas from the Henry Hub, which is located in Louisiana, and other location and transportation cost factors. In addition, our oil production, which consists of a combination of sweet and sour oil, typically sells at a discount to the NYMEX-WTI price due to quality and location differentials.
 
The adjustments we have made to reflect the basis differentials for our forecasted production during the twelve months ending December 31, 2012 are presented in the following table and shown per Bbl for oil and per MMBtu as well as per Mcf for natural gas, as reflected in our reserve reports:
 
                         
    Oil     Natural Gas  
Operating Area
  Per Bbl     Per MMBtu     Per Mcf  
 
South Texas
  $ (5.13 )   $ (0.13 )   $ 0.05  
East Texas
  $ (3.96 )   $ (0.36 )   $ (0.26 )
                         
Weighted Average
  $ (4.28 )   $ (0.21 )   $ (0.05 )
 
In addition, some of our pro forma production has transportation, gathering, and marketing charges deducted from the prices we realize. In areas where firm transportation capacity is contracted separately from the counterparties purchasing the natural gas, an additional adjustment is made as a deduction. The transportation costs are necessary to minimize risk of flow interruption to the markets.
 
Use of Commodity Derivative Contracts.  At the closing of this offering, Memorial Resource will contribute specific commodity derivative contracts. For purposes of the forecast in this prospectus, we have assumed that such commodity derivative contracts will cover 30 MMcfe/d, or approximately 62% of our total forecasted production of 49 MMcfe/d for the twelve months ending December 31, 2012. We have assumed that the assigned commodity derivative contracts will consist of put, collar and swap agreements for oil, NGLs and natural gas. The table below shows the volumes, benchmark price and prices we have assumed for our commodity derivative contracts for the twelve months ending December 31, 2012:
 
                                                         
    Puts   Collars   Swaps
                Weighted Average
       
        Weighted
      Price       Weighted
        Average
      Floor
  Ceiling
      Average
Oil (January 1, 2012 — December 31, 2012)   Bbl   Price   Bbl   Price   Price   Bbl   Price
 
NYMEX — WTI
        $       54,000     $ 86.67     $ 115.12              
% of forecasted oil production
                    54 %                                
% of total forecasted oil production
    54 %                                                
 


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    Puts     Collars     Swaps  
                      Weighted Average
             
          Weighted
          Price           Weighted
 
          Average
          Floor
    Ceiling
          Average
 
NGL (January 1, 2012 — December 31, 2012):   Bbl     Price     Bbl     Price     Price     Bbl     Price  
 
Mt. 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
                    24 %                                
% of total forecasted NGL production
    24 %                                                
 
                                                         
    Puts     Collars     Swaps  
          Weighted
          Weighted Average Price           Weighted
 
          Average
          Floor
    Ceiling
          Average
 
Natural Gas (January 1, 2012 — December 31, 2012):   MMBtu     Price     MMBtu     Price     Price     MMBtu     Price  
 
NYMEX — Henry Hub
        $       2,454,000     $ 4.98     $ 5.74       180,000     $ 4.94  
TETCO South Texas Basis
    840,000     $ 4.80       2,400,000     $ 4.68     $ 6.03       720,000     $ 5.51  
NGPL TexOk Basis
                900,000     $ 5.49     $ 6.57       396,000     $ 6.31  
Houston Ship Channel Basis
                1,680,000     $ 4.28     $ 5.65       960,000     $ 4.84  
                                                         
Total Natural Gas Hedges
    840,000     $ 4.80       7,434,000     $ 4.79     $ 5.91       2,256,000     $ 5.32  
% of forecasted natural gas production
    5 %             45 %                     14 %        
% of total forecasted natural gas production
    64 %                                                

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Operating Revenues and Realized Commodity Derivative Gains.  The following table illustrates the primary components of operating revenues and realized commodity derivative gains on a pro forma basis for the year ended December 31, 2010 and the twelve months ended September 30, 2011 and on a forecasted basis for the twelve months ending December 31, 2012:
 
                         
                Forecasted
 
    Pro Forma
    Pro Forma
    Twelve Months
 
    Year Ended
    Twelve Months
    Ending
 
    December 31,
    Ended
    December 31,
 
    2010     September 30, 2011     2012  
    (Unaudited)
 
    ($ in millions)  
 
Oil:
                       
Oil revenues
  $ 7.9     $ 8.7     $ 8.9  
Oil derivative contracts gain (loss)(1)
                (0.0 )
                         
Total
  $ 7.9     $ 8.7     $ 8.9  
NGLs:
                       
NGLs revenues
  $ 10.2     $ 10.4     $ 8.1  
NGLs derivative contracts gain (loss)(1)
                0.0  
                         
Total
  $ 10.2     $ 10.4     $ 8.1  
Natural gas:
                       
Natural gas revenues
  $ 69.7     $ 66.6     $ 66.9  
Natural gas derivative contracts gain (loss)(1)
                9.1  
                         
Total
  $ 69.7     $ 66.6     $ 76.0  
Total:
                       
Operating Revenues
  $ 87.8     $ 85.7     $ 83.9  
Commodity derivative contracts gain (loss)(1)
                9.1  
                         
Operating revenue and realized commodity derivative contract gains
  $ 87.8     $ 85.7     $ 93.0  
                         
 
 
(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 62% of our total forecasted production for the twelve months ending December 31, 2012.
 
Capital Expenditures and Expenses
 
Capital Expenditures.  Our estimated cash reserves for maintenance capital expenditures for the twelve months ending December 31, 2012 of $9.2 million represents our estimate of maintenance capital expenditures necessary to maintain our average net production of 49 MMcfe/d through December 31, 2015. We anticipate replacing declining production and reserves through the drilling and completing of wells on our undeveloped properties and through the acquisition of producing and non-producing oil and natural gas properties from Memorial Resource and from third parties. As part of our maintenance capital expenditures, we estimate that, during the forecast period, we will drill 7 gross (3.4 net) wells at an aggregate net cost of approximately $5.1 million and spend approximately $3.9 million on workovers, recompletions and other field-related costs.
 
Our forecast for the twelve months ending December 31, 2012 does not reflect any material growth capital expenditures or acquisitions. We anticipate spending approximately $59 million on growth capital expenditures over the next five years to further develop our properties and increase our production level above our targeted production rate. While we anticipate making all of these growth capital expenditures over the next five years and believe we have adequate external funding sources, the timing of such expenditures are


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expected to be uneven. We expect to spend approximately $1.0 million on growth capital expenditures on a forecasted basis for the twelve months ending December 31, 2012. Although we may make acquisitions during the twelve months ending December 31, 2012, our forecast does not reflect any acquisitions, as we cannot assure you that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase agreements and as any such acquisitions are expected to be funded with external sources of funding.
 
Lease Operating Expenses.  The following table summarizes pro forma lease operating expenses on an aggregate basis and on a per Mcfe basis for the year ended December 31, 2010 and the twelve months ended September 30, 2011 and forecasted lease operating expenses on an aggregate basis and on a per Mcfe basis for the twelve months ending December 31, 2012:
 
<
                         
            Forecasted
    Pro Forma
  Pro Forma
  Twelve Months
    Year Ended
  Twelve Months
  Ending