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Table of Contents

As filed with the Securities and Exchange Commission on December 5, 2012

Registration No. 333-185051

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 1

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   1311   90-0726667

(State or other jurisdiction of

incorporation or organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(IRS Employer

Identification Number)

1301 McKinney, Suite 2100

Houston, Texas 77010

(713) 588-8300

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

Kyle N. Roane

General Counsel and Corporate Secretary

Memorial Production Partners GP LLC

1301 McKinney, Suite 2100

Houston, Texas 77010

(713) 588-8300

(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

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.  ¨

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.  ¨

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

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

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

 

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

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of Securities to be Registered   Proposed Maximum Aggregate
Offering Price (1)(2)
  Amount of Registration Fee

Common units representing limited partner interests

  $215,000,000   $29,326

 

 

(1) Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.
(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o). The Registrant has previously paid $27,962 for the registration of $205,000,000 of proposed maximum aggregate offering price in connection with the Registrant’s Registration Statement on Form S-1 (File No. 333-185051) filed on November 20, 2012 and is paying $1,364 for the registration of an additional $10,000,000 of proposed maximum aggregate offering price registered herewith.

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.

 

 

 


Table of Contents

The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

Subject to Completion dated December 5, 2012

PRELIMINARY PROSPECTUS

 

LOGO

Memorial Production Partners LP

10,500,000 Common Units

Representing Limited Partner Interests

 

 

Memorial Production Partners LP is offering 10,500,000 common units representing limited partner interests. Our common units are listed on the NASDAQ Global Market under the symbol “MEMP.” On December 4, 2012, the last reported sale price of our common units on the NASDAQ Global Market was $18.25 per common unit.

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 23 of this prospectus and the other risk factors incorporated herein by reference into this prospectus.

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

   $         $     

Proceeds, before expenses, to Memorial Production Partners LP

   $         $     

 

 

To the extent that the underwriters sell more than 10,500,000 common units in this offering, the underwriters have the option to purchase up to an additional 1,575,000 common units on the same terms and conditions as set forth above.

The underwriters expect to deliver the common units on or about                     , 2012.

 

 

 

RAYMOND JAMES
  CITIGROUP
    BOFA MERRILL LYNCH
      BARCLAYS
        RBC CAPITAL MARKETS
          WELLS FARGO SECURITIES

 

OPPENHEIMER & CO.   SANDERS MORRIS HARRIS   WUNDERLICH SECURITIES

                    , 2012


Table of Contents

LOGO


Table of Contents

TABLE OF CONTENTS

 

     Page  

Summary

     1   

Overview

     1   

Beta Acquisition

     2   

Recent Developments

     4   

Our Properties

     5   

Our Business Strategies

     5   

Our Competitive Strengths

     6   

Our Principal Business Relationships

     7   

Risk Factors

     8   

Our Ownership and Organizational Structure

     9   

Principal Executive Offices and Internet Address

     10   

Management of the Partnership

     10   

Summary of Conflicts of Interest and Fiduciary Duties

     10   

The Offering

     11   

Summary Historical and Pro Forma Combined Financial Data

     15   

Non-GAAP Financial Measure

     18   

Summary and Pro Forma Reserve and Operating Data

     21   

Risk Factors

     23   

Risks Related to Our Business

     23   

Risks Inherent in an Investment in Us

     41   

Tax Risks to Unitholders

     53   

Use of Proceeds

     58   

Capitalization

     59   

Beta Acquisition

     60   

Overview of Acquisition

     60   

Reasons for Acquisition

     60   

Beta Field

     61   

Beta Properties

     61   

Hedging

     62   

Purchase and Sale Agreement and Seller Note

     62   

Business and Properties Overview

     64   

Overview

     64   

Recent Developments

     65   

Our Properties

     66   

Our Business Strategies

     66   

Our Competitive Strengths

     68   

Our Principal Business Relationships

     70   

Our Areas of Operations

     71   

 

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Table of Contents

Our Oil and Natural Gas Data

     72   

Operations

     78   

Price Range of Common Units and Distribution

     81   

Provisions of Our Partnership Agreement Relating to Cash Distributions

     82   

Distributions of Available Cash

     82   

Operating Surplus and Capital Surplus

     83   

Capital Expenditures

     86   

Subordination Period

     88   

Distributions of Available Cash from Operating Surplus During the Subordination Period

     90   

Distributions of Available Cash from Operating Surplus After the Subordination Period

     90   

General Partner Interest and Incentive Distribution Rights

     91   

Percentage Allocations of Available Cash from Operating Surplus

     91   

General Partner’s Right to Reset Incentive Distribution Levels

     92   

Distributions from Capital Surplus

     93   

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

     94   

Distributions of Cash Upon Liquidation

     95   

Security Ownership of Certain Beneficial Owners and Management

     97   

Certain Relationships and Related Party Transactions

     99   

Distributions and Payments to Our General Partner and Its Affiliates

     99   

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

     100   

Related Party Agreements

     101   

Review, Approval or Ratification of Transactions with Related Persons

     103   

Conflicts of Interest and Fiduciary Duties

     105   

Conflicts of Interest

     105   

Fiduciary Duties

     113   

Description of the Common Units

     117   

The Units

     117   

Transfer Agent and Registrar

     117   

Transfer of Common Units

     117   

The Partnership Agreement

     119   

Organization and Duration

     119   

Purpose

     119   

Cash Distributions

     119   

Capital Contributions

     119   

Limited Voting Rights

     120   

Applicable Law; Forum, Venue and Jurisdiction

     121   

Limited Liability

     122   

Issuance of Additional Securities

     123   

Amendment of the Partnership Agreement

     123   

 

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Table of Contents

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

     126   

Termination and Dissolution

     127   

Liquidation and Distribution of Proceeds

     127   

Withdrawal or Removal of Our General Partner

     127   

Transfer of General Partner Units

     129   

Transfer of Incentive Distribution Rights

     129   

Transfer of Ownership Interests in Our General Partner

     129   

Change of Management Provisions

     129   

Limited Call Right

     130   

Meetings; Voting

     130   

Status as Limited Partner

     131   

Non-Citizen Assignees; Redemption

     131   

Non-Taxpaying Assignees; Redemption

     132   

Indemnification

     132   

Reimbursement of Expenses

     132   

Books and Reports

     133   

Right to Inspect Our Books and Records

     133   

Registration Rights

     134   

Units Eligible for Future Sale

     135   

Material Tax Consequences

     136   

Partnership Status

     137   

Limited Partner Status

     138   

Tax Consequences of Unit Ownership

     139   

Tax Treatment of Operations

     146   

Disposition of Common Units

     151   

Uniformity of Units

     153   

Tax-Exempt Organizations and Other Investors

     154   

Administrative Matters

     155   

State, Local and Other Tax Considerations

     158   

Investment in Memorial Production Partners LP by Employee Benefit Plans

     159   

Underwriting

     161   

Validity of the Common Units

     168   

Experts

     168   

Where You Can Find More Information

     169   

Forward-Looking Statements

     170   

Index to Financial Statements

     F-1   

Appendix A Glossary of Terms

     A-1   

Appendix B Netherland, Sewell  & Associates, Inc. Summary Reserve Report (Memorial Production Partners LP)

     B-1   

Appendix C Netherland, Sewell & Associates, Inc. Summary Reserve Report (Beta Properties)

     C-1   

 

iii


Table of Contents

You should rely only on the information contained in or incorporated by reference this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should not assume that the information appearing in this prospectus, and the information we have previously filed with the Securities and Exchange Commission, or SEC, that is incorporated by reference herein, is accurate as of any date other than its respective date. Our business, financial condition, results of operations and prospects may have changed since that date.

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.”

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:

 

  Ÿ  

“Memorial Production Partners,” “the partnership,” “we,” “our,” “us” or like terms refer collectively to Memorial Production Partners LP and its subsidiaries;

 

  Ÿ  

“our general partner” refers to Memorial Production Partners GP LLC, our general partner;

 

  Ÿ  

“our predecessor” refers collectively to (a) BlueStone Natural Resources Holdings, LLC and its wholly-owned subsidiaries and certain oil and natural gas properties owned by Classic Hydrocarbons Holdings, L.P. for all periods prior to the closing of our initial public offering, (b) for periods after April 8, 2011 through the closing of our initial public offering, certain oil and natural gas properties owned by WHT Energy Partners LLC and (c) certain oil and natural gas properties the partnership acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates, all of which are collectively our predecessor for accounting and financial reporting purposes;

 

  Ÿ  

“the Funds” refers collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P.; and

 

  Ÿ  

“Memorial Resource” refers collectively to Memorial Resource Development LLC and its subsidiaries.

We include a glossary of some of the oil and natural gas terms used in this prospectus in Appendix A.

 

iv


Table of Contents

Other Information

Our estimated proved reserve information at September 30, 2012 contained in this prospectus is based on a reserve report audited by the independent petroleum engineers of Netherland, Sewell & Associates, Inc., or NSAI. Estimates comprising approximately 97% of the total proved reserves in our reserve report were prepared by NSAI and the remaining portion was prepared by our internal reserve engineers. The estimated proved reserve information attributable to the Beta properties (described herein) at September 30, 2012 is based on a reserve report prepared by NSAI. The summaries of our reserve report and the reserve report with respect to the Beta properties are included as Appendices B and C, respectively, of this prospectus.

Unless we indicate otherwise in this prospectus, our production and operating data does not give effect to the acquisitions in 2012 accounted for as transactions between entities under common control until after the closing date of the respective acquisitions.

 

v


Table of Contents

SUMMARY

This summary highlights information contained elsewhere in this prospectus and in the documents incorporated by reference herein. You should read the entire prospectus, including the documents incorporated by reference herein, as described under “Where You Can Find More Information,” before investing in our common units. You should read carefully “Risk Factors” beginning on page 23 and the other risk factors incorporated by reference herein for information about important risks that you should consider before making an investment decision. The information presented in this prospectus assumes that the underwriters do not exercise their option to purchase additional common units, unless otherwise indicated.

Memorial Production Partners LP

Overview

We are a Delaware limited partnership formed in April 2011 by Memorial Resource to own, acquire and exploit 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. Our assets consist primarily of producing oil and natural gas properties and are principally located in Texas and Louisiana and, following completion of the Beta acquisition described below, offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs with well-known geologic characteristics and long-lived, predictable production profiles and modest capital requirements. As of September 30, 2012:

 

  Ÿ  

Our total pro forma estimated proved reserves were approximately 599 Bcfe, of which approximately 64% were natural gas and 61% were classified as proved developed reserves;

 

  Ÿ  

We produced from 1,667 gross (729 net) producing wells pro forma across our properties, with an average working interest of 44%, and we or Memorial Resource operated 95% of the properties in which we have interests; and

 

  Ÿ  

Our average pro forma net production for the nine months ended September 30, 2012 was 79.8 MMcfe/d, implying a reserve-to-production ratio of 20.6 years.

Since completing our initial public offering in December 2011, we have completed four acquisitions and will close the Beta acquisition simultaneously with the closing of this offering. After giving effect to these acquisitions, we have:

 

  Ÿ  

Diversified our commodity mix by adding significant oil and NGL rich assets, and expanded our geographic footprint;

 

  Ÿ  

Increased our average net production from 48.8 MMcfe/d for the year ended December 31, 2011 to 79.8 MMcfe/d pro forma for the nine months ended September 30, 2012;

 

  Ÿ  

Increased our estimated net proved reserves from 324 Bcfe as of December 31, 2011 to 599 Bcfe pro forma as of September 30, 2012; and

 

  Ÿ  

Increased our organic drilling and recompletion opportunities from 345 as of December 31, 2011 to 573 pro forma as of September 30, 2012.

 

 

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Table of Contents

During that same period, we also increased our quarterly distribution rate from $0.4750 per unit to $0.4950 per unit, which represents an annualized distribution of $1.98 per unit and a 4.2% increase over the initial distribution. The board of directors of our general partner has also approved, subject to the completion of the Beta acquisition, a further increase in our distribution rate attributable to the fourth quarter of 2012 to $0.5075 per unit, representing an annualized distribution of $2.03 per unit and a 6.8% increase over our initial annualized distribution rate.

Beta Acquisition

On November 19, 2012, we, through a wholly-owned subsidiary, entered into a purchase and sale agreement pursuant to which we agreed to purchase all of the outstanding equity interests in Rise Energy Operating, LLC and its subsidiaries, which collectively own certain oil and gas producing properties and assets offshore Southern California, for approximately $271 million, including $3 million of working capital and other customary adjustments. We refer to this transaction as the “Beta acquisition” and the properties and assets to be acquired as the “Beta properties.” The Beta acquisition will close simultaneously with the completion of this offering.

The Beta properties primarily consist of a 51.75% working interest in three Pacific Outer Continental Shelf blocks covering the Beta Field, and are located in federal waters approximately 11 miles offshore the Port of Long Beach, California. We will be the operator of the Beta properties. Associated facilities include three conventional wellhead and production processing platforms, a 17.5-mile pipeline and an onshore tankage and metering facility. Two of the platforms are bridge connected and stand in approximately 260 feet of water, while the third platform stands in approximately 700 feet of water.

The Beta properties were first discovered in 1976 by Royal Dutch Shell PLC and have been in production since January 1981. As of September 30, 2012, the total estimated proved reserves attributable to the Beta properties were approximately 14.3 MMBbls, based on the reserve report prepared by NSAI, of which approximately 100% were oil and approximately 70% were classified as proved developed reserves, with a standardized measure of $392.8 million. The average net production associated with the Beta properties for the nine months ended September 30, 2012 was 1,574 Bbls/d, implying a reserve-to-production ratio of 24.9 years.

The Beta acquisition complements our existing properties because:

 

  Ÿ  

the assets exhibit a stable long-lived production profile with an estimated average annual proved developed producing decline rate of approximately 5%;

 

  Ÿ  

the assets have a diverse distribution of reserve value, with 51 gross (26 net) producing wells, none of which contains in excess of 5% of the total estimated proved reserves attributable to the Beta properties;

 

  Ÿ  

the assets have relatively high operating margins and moderate capital expenditure requirements;

 

  Ÿ  

the assets present multiple low-cost development opportunities to us such as injection enhancement, drilling, and recompletion opportunities and include 4.4 MMBbls of estimated proved undeveloped reserves, which we expect, in conjunction with the appropriately-sized platforms and production facilities, will allow for lower-cost and lower-risk growth;

 

 

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  Ÿ  

the acquisition will further diversify both our asset mix, by adding a significant amount of oil, and our geographic basins;

 

  Ÿ  

we expect that reservoir injection enhancement programs, which replace the loss of reservoir pressure, could significantly increase future production and reserves from these properties;

 

  Ÿ  

Memorial Resource expects to retain substantially all of the operating personnel managing the Beta properties, which we expect will allow for seamless operations and permit us to take advantage of such personnel’s significant experience with and knowledge of the assets as well as the California operating and regulatory environment;

 

  Ÿ  

we will be the operator of the Beta properties, which we expect will allow us to manage operating costs and better control capital expenditures, as well as the timing of development activities; and

 

  Ÿ  

we expect to benefit from oil prices determined using the Midway-Sunset benchmark, which currently receive premium pricing to WTI crude.

We expect to finance the Beta acquisition with cash on hand, borrowings under our revolving credit facility, the net proceeds from this offering and, potentially, promissory notes payable to the seller. The closing of the Beta acquisition is not contingent on the completion of this offering, and we have the option to pay the entire purchase price with borrowings under our revolving credit facility and promissory notes payable to the seller. In connection with the completion of the Beta acquisition, we have secured commitments from our lenders to increase the current borrowing base under our revolving credit facility from $380 million to $460 million. Please read “Use of Proceeds” and “Beta Acquisition” for more information about the application of the net proceeds from this offering and the Beta acquisition.

As part of the Beta acquisition, we will acquire crude oil hedges from the closing of the acquisition through 2015. The acquired hedges will cover a significant portion of 2013 crude oil volumes as well as volumes in 2014 and 2015. In addition to the acquired hedges and consistent with our hedging policy, we entered into additional crude oil hedges through 2017 that cover 65% to 85% of our targeted crude oil production per year. Please read “Business and Properties Overview—Operations—Derivative Activities.”

The seller of the Beta properties is primarily owned by two of the Funds; because this is a related party transaction, the conflicts committee of the board of directors of our general partner reviewed the Beta acquisition and the terms of the related transactions and agreements, engaged and consulted with its independent financial and legal advisors with respect thereto, and granted “special approval” with respect to the Beta acquisition pursuant to our limited partnership agreement. Based upon that special approval, and upon the recommendation of the conflicts committee, the board of directors of our general partner also approved the Beta acquisition. Please read “Conflicts of Interest and Fiduciary Duties” and “Certain Relationships and Related Party Transactions—Related Party Agreements—Acquisitions of Oil and Natural Gas Producing Properties.”

 

 

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Recent Developments

Distribution Rate Increase Announcement

On November 19, 2012, the board of directors of our general partner approved, subject to the completion of the Beta acquisition, an increase in our distribution rate attributable to the fourth quarter of 2012 to $0.5075 per unit, representing an annualized distribution of $2.03 per unit. This represents a 2.5% increase over our current annualized distribution of $1.98 per unit and a 6.8% increase over our initial annualized distribution of $1.90 per unit.

Other 2012 Acquisitions

We seek to acquire properties with long-lived reserves, low production decline rates and identified and predictable development potential. During 2012, we completed four acquisitions that met such criteria for an aggregate of $175.2 million. These acquisitions were consistent with our business strategies of utilizing our relationships with Memorial Resource and the Funds to acquire producing oil and natural gas properties from them that meet our acquisition criteria as well as to use such relationships to increase the size and scope of third-party acquisition targets we pursue. Two of our acquisitions were from Memorial Resource, one acquisition was made via a joint bid with Memorial Resource from an undisclosed third party, and the fourth acquisition was from a third party. Below is a summary of information relating to our 2012 acquisitions.

 

Date

 

Transaction Structure

  Average  Net
Production

MMcfe/d(1)
   

Location

  Net Aggregate
Purchase  Price

($ in millions)
 

September 2012

  Third-Party Acquisition     12.6      East Texas   $ 93.2   

May 2012

  Acquisition from Memorial Resource     4.2      East Texas     27.0   

May 2012

  Joint Bid Third-Party Acquisition with Memorial Resource     3.5      East Texas/North Louisiana     36.5   

April 2012

  Acquisition from Memorial Resource     2.3      East Texas     18.5   
   

 

 

     

 

 

 

Total

      22.6        $ 175.2   
   

 

 

     

 

 

 

 

(1) Estimated by management at the time of the respective acquisitions.

At September 30, 2012, these acquired properties contained 209 Bcfe of estimated proved reserves. In completing these acquisitions, we have increased our base of producing properties, increased our amount of total proved reserves and expanded our footprint within East Texas/North Louisiana. These acquisitions have also increased our ability to organically maintain or increase our production by contributing an additional 166 proved, low risk infill drilling, recompletion and development opportunities to our inventory. We expect to continue to exploit these opportunities to maintain our target production levels over time, as well as to continue evaluating additional acquisition opportunities.

 

 

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Our Properties

Our properties are located in South Texas and East Texas/North Louisiana and, after giving effect to the Beta acquisition, offshore Southern California and consist of large, mature 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, modest capital requirements and substantial opportunities for further exploitation and development. The following table sets forth certain information with regard to our estimated proved reserves and the estimated proved reserves attributable to the Beta properties at September 30, 2012, our pro forma estimated proved reserves as of September 30, 2012, and pro forma average net daily production for the nine months ended September 30, 2012.

 

    Memorial
Production
Partners LP
Historical
    Beta
Properties

Historical
    Memorial Production Partners LP Pro Forma  

Region

  Estimated
Net Proved
Reserves
Bcfe (1)
    Estimated
Net Proved
Reserves
MMBbls
    Estimated Net
Proved Reserves
          Average Net
Production
    Average
Reserve-to-
Production
Ratio (3)

(years)
    Producing
Wells
 
      Bcfe (1)     % Oil
and
NGL
    %
Natural
Gas
    %
Proved
Developed
    Standardized
Measure (2)

(in millions)
    MMcfe/d     %
of
Total
      Gross     Net  

South Texas

    176.1               176.1        14     86     84   $ 127.9        27.5        34     17.6        515        408   

East Texas/North Louisiana

    337.2               337.2        31     69     47     299.4        42.9        54     21.5        1,101        295   

California

           14.3        86.0        100     0     70     392.8        9.4        12     24.9        51        26   
 

 

 

   

 

 

   

 

 

         

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    513.3        14.3        599.3        36     64     61   $ 820.1        79.8        100     20.6        1,667        729   
 

 

 

   

 

 

   

 

 

         

 

 

   

 

 

   

 

 

     

 

 

   

 

 

 

 

(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 calculated in accordance with Accounting Standards Codification, or ASC, Topic 932, Extractive Activities—Oil and Gas. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to commodity derivative contracts.
(3) The average reserve-to-production ratio is calculated by dividing our estimated pro forma net proved reserves as of September 30, 2012 by our annualized average pro forma net production for the nine months ended September 30, 2012.

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:

 

  Ÿ  

Maintain and grow a stable production profile through accretive acquisitions and lower-risk development.

 

  Ÿ  

Exploit opportunities on our current properties and manage our operating costs and capital expenditures.

 

  Ÿ  

Utilize our relationship with Memorial Resource, the Funds, and their respective affiliates (including Natural Gas Partners) to gain access to and, from time to time, acquire from them producing oil and natural gas properties that meet our acquisition criteria.

 

 

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  Ÿ  

Leverage our relationships with Memorial Resource, the Funds, and their respective affiliates (including Natural Gas Partners) to participate with them in acquisitions of third party producing properties and to increase the size and scope of our potential third-party acquisition targets.

 

  Ÿ  

Reduce exposure to commodity price risk and stabilize cash flows through a disciplined commodity hedging policy.

 

  Ÿ  

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 Overview—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:

 

  Ÿ  

Our diversified asset portfolio is characterized by long-lived reserves with low geologic risk, significant production history and predictable production decline rates.

 

  Ÿ  

Our relationships with Memorial Resource, the Funds, and their respective affiliates (including Natural Gas Partners), which we believe (i) provide us with access to a portfolio of additional oil and natural gas properties that meet our acquisition criteria and (ii) help us with access to and in the evaluation and execution of future acquisitions.

 

  Ÿ  

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.

 

  Ÿ  

Our diverse distribution of reserve value, with 1,667 gross (729 net) producing wells pro forma as of September 30, 2012, none of which contains estimated proved reserves in excess of 2% of our total combined pro forma estimated proved reserves as of September 30, 2012.

 

  Ÿ  

Our substantial inventory of proved operated infill drilling, recompletion and development opportunities.

 

  Ÿ  

Our competitive cost of capital and financial flexibility.

 

  Ÿ  

Our management team’s extensive experience in the acquisition, development and successful integration of oil and natural gas assets.

For a more detailed discussion of our competitive strengths, please read “Business and Properties Overview—Our Competitive Strengths.”

 

 

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Our Principal Business Relationships

Our Relationship with Memorial Resource

Memorial Resource is a Delaware limited liability company formed by the Funds to own, acquire, exploit and develop oil and natural gas properties and to own our general partner. As part of our formation transactions in connection with our initial public offering, the Funds contributed to Memorial Resource their respective ownership of five separate portfolio companies (including those comprising 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 contributed our properties to us. Memorial Resource is engaged in its business with the objective of growing its reserves, production and cash flows, as well as owning our general partner and a significant limited partner interest in us.

Memorial Resource is our largest unitholder, holding 7,061,294 common units (approximately 25.7% of all outstanding immediately following this offering) and 5,360,912 subordinated units (100% of all outstanding), and owns all of the voting interests in our general partner and 50% of the economic interest in our incentive distribution rights. Memorial Resource has pledged our common and subordinated units that it owns, as well as its ownership interest in our general partner, as security under its senior secured revolving credit facility in addition to certain other assets of Memorial Resource. Our general partner has entered into an omnibus agreement with Memorial Resource and the Partnership in which Memorial Resource has agreed to provide the administrative, management and operational services that we believe are necessary to allow our general partner to manage, operate and grow our business.

As of June 30, 2012, excluding the properties sold to us during 2012, Memorial Resource had (i) total estimated proved reserves of over 1,235 Bcfe, primarily located in East Texas, North Louisiana and the Rockies and (ii) interests in over 579,570 gross (335,323 net) acres of 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 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/North Louisiana 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.

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. For example, during 2012 we acquired two sets of properties from Memorial Resource, and we also completed an acquisition of properties via a joint bid with Memorial Resource. However, Memorial Resource regularly evaluates 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. Although we believe Memorial Resource is incentivized to offer properties to us for purchase, none of Memorial Resource, the Funds or any of their respective affiliates has any obligation to sell or offer properties to us. Please read “Conflicts of Interest and Fiduciary Duties.”

 

 

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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 cumulative committed capital of approximately $10.5 billion since inception, organized to make investments in the natural resources sector. NGP is part of the investment platform of NGP Energy Capital Management, a premier investment franchise in the natural resources industry, which together with its affiliates has managed approximately $13 billion in cumulative committed capital since inception. 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 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 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. For example, we will acquire the Beta properties from a seller that is primarily owned by two of the Funds.

Risk Factors

An investment in our common units involves risks. Please read the full discussion of the risk factors described under “Risk Factors” beginning on page 23 of this prospectus.

 

 

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Our Ownership and Organizational Structure

The diagram below illustrates our ownership and organizational structure based on total units outstanding after giving effect to this offering and assumes that the underwriters do not exercise their option to purchase additional common units.

 

     Units      Ownership
Interest
 

Common units held by the public(1)

     20,385,609         62.1

Common units held by Memorial Resource

     7,061,294         21.5

Subordinated units held by Memorial Resource

     5,360,912         16.3

General partner units

     32,840         0.1
  

 

 

    

 

 

 

Total

     32,840,655         100.0
  

 

 

    

 

 

 

 

LOGO

 

(1) Includes common units awarded under the Memorial Production Partners GP LLC Long-Term Incentive Plan.

 

 

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Principal Executive Offices and Internet Address

Our principal executive offices are located at 1301 McKinney Street, Suite 2100, Houston, Texas 77010, and our phone number is (713) 588-8300. Our website address is www.memorialpp.com. We make our periodic reports and other information filed with or furnished to 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. The board of directors of our general partner has seven members, three of whom are independent directors. 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. Neither we nor our subsidiaries 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 reimburse our general partner and its affiliates for all expenses they incur or payments they make on our behalf. Pursuant to our omnibus agreement, Memorial Resource provides us and our general partner with operating, management, and administrative services, which we believe provides us with significant technical expertise and experience that allows us to identify and execute cost-reducing exploitation and operational improvements on both our existing properties and new acquisitions. For a detailed description of our management, please read “Directors, Executive Officers and Corporate Governance” included in our Annual Report on Form 10-K for the year ended December 31, 2011, our Current Report on Form 8-K filed on August 9, 2012 and our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, all of which are incorporated by reference herein.

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 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 have economic interests, investments and other economic incentives in affiliates of the Funds, including indirect economic interests in the Funds that own the seller of the Beta properties. As a result of these relationships, conflicts of interest may exist or 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 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.”

 

 

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The Offering

 

Common units offered hereby

10,500,000 common units or 12,075,000 common units if the underwriters exercise in full their option to purchase additional common units.

 

Units outstanding after this offering

27,446,903 common units and 5,360,912 subordinated units, representing 83.6% and 16.3%, respectively, limited partner interests in us (29,021,903 common units and 5,360,912 subordinated units, representing 84.3% and 15.6%, respectively, limited partner interests in us if the underwriters exercise in full their option to purchase additional common units). In addition, following this offering, our general partner will own general partner units representing an approximate 0.1% general partner interest in us.

 

Use of proceeds

We expect to receive approximately $         million in net proceeds from the sale of the 10,500,000 common units we are offering hereby, or $         million in net proceeds if the underwriters exercise in full their option to purchase additional common units, in each case including our general partner’s proportionate capital contribution and after deducting underwriting discounts but before estimated offering expenses. We intend to use these net proceeds to fund a portion of the approximate $271 million purchase price, which includes $3 million of working capital and other customary adjustments, for our pending Beta acquisition, which will close simultaneously with the closing of this offering. The closing of the Beta acquisition is not contingent on the completion of this offering. Please read “Use of Proceeds.”

 

Cash distributions

We paid a quarterly cash distribution of $0.4950 per common, subordinated and general partner unit for the third quarter of 2012 ($1.98 per unit on an annualized basis) on November 12, 2012 to unitholders of record as of November 1, 2012. This third quarter 2012 distribution represented an approximate 3% increase from the second quarter 2012 distribution of $0.48 per common, subordinated and general partner unit.

 

  On November 19, 2012, the board of directors of our general partner approved, subject to the completion of the Beta acquisition, an increase in our cash distribution rate attributable to the fourth quarter of 2012 to $0.5075 per unit, representing an annualized distribution of $2.03 per unit. This represents a 2.5% increase over our current annualized distribution of $1.98 per unit and a 6.8% increase over our initial annualized distribution of $1.90 per unit.

 

 

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  Within 45 days after the end of each quarter, we distribute our available cash from operations, after the establishment of cash reserves and the payment of fees and expenses and payments to our general partner and its affiliates, to unitholders of record on the applicable record date.

 

  Assuming our general partner maintains its current approximate 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;

 

   

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.”

 

Subordinated units

Memorial Resource owns 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 extends 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

 

 

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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.

 

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 manages us and operates our business. Unlike stockholders of a corporation, our unitholders have only limited voting rights on matters affecting our business. Our unitholders 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 66 2/3% 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 37.9% of our outstanding common and

 

 

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subordinated units (or 36.1% 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 25.7% of our outstanding common units (or 24.3% 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, 2015, such unitholders will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 20% of the cash distributed to such unitholders with respect to that period. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions” for information regarding the bases for this estimate.

 

Material tax consequences

For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”

 

Agreement to be bound by the partnership agreement

By purchasing a common unit, you will be admitted as a unitholder of our partnership and will be deemed to have agreed to be bound by all of the terms of our partnership agreement.

 

Listing and trading symbol

Our common units are listed on the NASDAQ Global Market under the symbol “MEMP.”

 

 

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Summary Historical and Pro Forma Combined Financial Data

The following table presents summary historical combined financial data of us and our predecessor and the unaudited pro forma financial data of Memorial Production Partners LP for the periods and as of the dates presented. The historical financial data presented in the following table consists of our consolidated financial data for all periods following the completion of our initial public offering on December 14, 2011 combined with the historical financial data of our predecessor.

The historical financial data presented was derived from our predecessor’s combined financial statements and our consolidated financial statements. The historical financial data should be read in conjunction with our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2012, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Financial Statements and Supplementary Data,” both of which are included in both our Annual Report on Form 10-K for the year ended December 31, 2011 and our Current Report on Form 8-K filed with the SEC on November 20, 2012, all of which are incorporated by reference herein.

Certain portions of our Annual Report on Form 10-K for the year ended December 31, 2011 were retrospectively revised within our Current Report on Form 8-K filed with the SEC on November 20, 2012 to give effect to our acquisitions of oil and gas properties from Memorial Resource in April and May 2012 as if we had owned them beginning on the dates Memorial Resource originally acquired them. Each of these transactions was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at Memorial Resource’s carrying value. The historical financial position and results attributable to these oil and gas properties were prepared from Memorial Resource’s cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported.

The selected unaudited pro forma financial data as of and for the nine months ended September 30, 2012, and for the year ended December 31, 2011, are derived from the unaudited pro forma condensed 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, 2012, in the case of the unaudited pro forma balance sheet, or as of January 1, 2011, in the case of the unaudited pro forma statements of operations. These transactions include:

 

  Ÿ  

Adjustments to reflect the acquisition of the Beta properties from Rise Energy Partners, LP simultaneously with the closing of this offering;

 

  Ÿ  

The issuance and sale by us to the public of 10,500,000 common units in this offering and the application of the net proceeds as described in “Use of Proceeds”;

 

  Ÿ  

Our borrowing of approximately $88.2 million under our revolving credit facility and the application of the proceeds as described in “Use of Proceeds”;

 

  Ÿ  

Adjustments to reflect certain third-party acquisitions in 2012 and 2011 as if these acquisitions had occurred on January 1, 2011;

 

 

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  Ÿ  

Adjustments related to certain operations that were included in our predecessor’s historical results in 2011 but were not contributed to us in connection with our initial public offering in December 2011; and

 

  Ÿ  

Other pro forma adjustments as further described in the unaudited pro forma condensed combined financial statements of Memorial Production Partners LP included elsewhere in this prospectus.

You should read the following table in conjunction with our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2012, our Current Report on Form 8-K filed with the SEC on November 20, 2012, our Annual Report on Form 10-K for the year ended December 31, 2011, all of which are incorporated by reference herein, and the historical financial statements of Rise Energy Operating, LLC and the unaudited pro forma condensed combined financial statements of Memorial Production Partners LP included elsewhere in this prospectus. Among other things, those historical and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the following information.

 

 

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The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in evaluating the operating performance and 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 the most directly comparable financial measure calculated and presented in accordance with GAAP.

 

    Historical     Pro Forma  
    Year Ended December 31,     Nine Months
Ended September 30,
    Year
Ended
December  31,
    Nine Months
Ended
September 30,
 
    2009     2010     2011     2011     2012     2011     2012  
                      (Unaudited)     (Unaudited)  
(in thousands)                                          

Statement of Operations Data:

             

Revenues

             

Oil and natural gas sales

  $ 32,032      $ 47,435      $ 84,058      $ 62,412      $ 54,725      $ 194,052      $ 120,771   

Other income

    319        1,433        825        599        163        3,632        1,456   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

    32,351        48,868        84,883        63,011        54,888        197,684        122,227   

Costs and expenses:

             

Lease operating

    12,191        14,878        24,474        16,424        19,118        49,744        37,040   

Exploration

    2,690        39        56        56        414        280        415   

Production taxes

    2,032        2,838        4,790        5,977        5,215        8,631        6,488   

Depreciation, depletion and amortization

    19,011        24,543        30,052        22,133        23,548        48,227        34,121   

Impairment of proved oil and natural gas properties

    3,480        11,800        15,141        3,047               11,095          

General and administrative

    5,845        7,102        10,399        6,714        6,820        14,368        9,976   

Accretion of assets retirement obligations

    326        672        1,069        776        840        3,498        2,696   

(Gain) loss on commodity derivative instruments

    (11,121     (11,213     (33,325     (14,596     (5,622     (34,767     (6,914

Gain on sale of properties

    (7,851     (1     (63,024     (62,764     (192     (62,280     (192

Other, net

    448        1,194        1,908        1,851        468        2,024        468   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

    27,051        51,852        (8,460     (20,382     50,609        40,820        84,098   

Operating income (loss)

    5,300        (2,984     93,343        83,393        4,279        156,864        38,129   

Other income (expense)

             

Interest expense, net

    (2,937     (4,438     (7,268     (5,433     (7,943     (10,691     (12,271

Amortization of investment premium

                                       (606     (170
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

  $ 2,363      $ (7,422   $ 86,075      $ 77,960      $ (3,664   $ 145,567      $ 25,688   

Income tax expense

           (225     (122     (122     (26     (57     (26
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

  $ 2,363      $ (7,647   $ 85,953      $ 77,838      $ (3,690   $ 145,510      $ 25,662   

Net income (loss) attributable to predecessor

    2,363        (7,647     79,361        77,838        1,001                 

Net income (loss) attributable to non-controlling interest

                                       (146     17   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to partners

  $      $      $ 6,592      $      $ (4,691   $ 145,656      $ 25,645   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash Flow Data:

             

Net cash provided by operating activities

  $ 17,433      $ 27,496      $ 42,706      $ 31,668      $ 42,094       

Net cash (used in) investing activities

    (42,138     (135,081     (169,652     (166,412     (144,617    

Net cash provided by financing activities

    28,419        107,942        122,380        139,285        102,473       

Other Financial Data:

             

Adjusted EBITDA (unaudited)

  $ 29,713      $ 31,040      $ 52,301      $ 37,201      $ 55,453      $ 130,743      $ 93,972   

Balance Sheet Data:

    (Unaudited)               

Working capital

  $ 9,494      $ 4,116      $ 25,541      $ 16,467      $ 20,516        $ 29,243   

Total assets

    174,826        292,433        493,246        519,518        611,999          811,074   

Total debt

    61,784        115,428        120,000        203,228        293,000          381,168   

Total equity

    101,445        149,114        354,021        279,192        281,315          315,661   

 

 

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Non-GAAP Financial Measure

Partnership and Pro Forma Financial Information

We include in this prospectus the non-GAAP financial measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and reconciliation of Adjusted EBITDA to the most directly comparable financial measure calculated and presented in accordance with GAAP.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss):

 

  Ÿ  

Plus:

 

  Ÿ  

Interest expense, including realized and unrealized losses on interest rate derivative contracts;

 

  Ÿ  

Income tax expense;

 

  Ÿ  

Depreciation, depletion and amortization;

 

  Ÿ  

Impairment of goodwill and long-lived assets (including oil and natural gas properties);

 

  Ÿ  

Accretion of asset retirement obligations;

 

  Ÿ  

Unrealized losses on commodity derivative contracts;

 

  Ÿ  

Losses on sale of assets and other, net;

 

  Ÿ  

Unit-based compensation expenses;

 

  Ÿ  

Exploration costs;

 

  Ÿ  

Acquisition related costs;

 

  Ÿ  

Amortization of investment premium;

 

  Ÿ  

Net operating cash flow from acquisitions, effective date through closing date; and

 

  Ÿ  

Other non-routine items that we deem appropriate.

 

  Ÿ  

Less:

 

  Ÿ  

Interest income;

 

  Ÿ  

Income tax benefit;

 

  Ÿ  

Unrealized gains on commodity derivative contracts;

 

  Ÿ  

Gains on sale of assets and other, net; and

 

  Ÿ  

Other non-routine items that we deem appropriate.

We are required to comply with certain Adjusted EBITDA-related metrics under our revolving credit facility.

 

 

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Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess:

 

  Ÿ  

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

 

  Ÿ  

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 uses 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

 

    Historical     Pro Forma  
    Year Ended December 31,     Nine Months
Ended
September 30,
    Year
Ended
December  31,
    Nine Months
Ended
September 30,
 
    2009     2010     2011     2011     2012     2011     2012  
(in thousands)   (Unaudited)     (Unaudited)     (Unaudited)  

Net income (loss)

  $ 2,363      $ (7,647   $ 85,953      $ 77,838      $ (3,690   $ 145,510      $ 25,662   

Interest expense, net

    2,937        4,438        7,268        5,433        7,943        10,691        12,271   

Income tax expense

           225        122        122        26        57        26   

Depreciation, depletion and amortization

    19,011        24,543        30,052        22,133        23,548        48,227        34,121   

Impairment

    3,480        11,800        15,141        3,047               11,095          

Accretion of asset retirement obligations

    326        672        1,069        776        840        3,498        2,696   

Unrealized (gains) losses on commodity derivative instruments

    6,453        (3,919     (25,381     (10,282     18,984        (27,986     17,031   

Gain on sale of properties

    (7,851     (1     (63,024     (62,764     (192     (62,280     (192

Unit-based compensation expense

                                993               993   

Acquisition related costs

    304        890        1,045        842        779        1,045        779   

Exploration costs

    2,690        39        56        56        414        280        415   

Amortization of investment premium

                                       606        170   

Net operating cash flow from acquisitions, effective date through closing date

                                5,808                 
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 29,713      $ 31,040      $ 52,301      $ 37,201      $ 55,453      $ 130,743      $ 93,972   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

 

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Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA

 

     Historical  
     Year Ended December 31,     Nine Months
Ended
September 30,
 
     2009     2010     2011     2011     2012  
(in thousands)    (Unaudited)     (Unaudited)  

Net cash provided by operating activities

   $ 17,433      $ 27,496      $ 42,706      $ 31,668      $ 42,094   

Changes in working capital

     8,838        (743     684        (1,595     2,500   

Interest expense

     2,937        4,438        7,268        5,433        7,943   

Premiums paid for derivatives

                   2,847        2,847          

Premiums received for derivatives

                   (1,008     (1,008       

Unrealized gain/(loss) on interest rate swaps

     310        (296     (776     (649     (3,699

Acquisition related costs

     304        890        1,045        842        779   

Amortization of deferred financing fees

     (109     (745     (465     (337     (386

Exploration costs

                                 414   

Net operating cash flow from acquisitions, effective date through closing date

                                 5,808   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 29,713      $ 31,040      $ 52,301      $ 37,201      $ 55,453   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

 

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Summary and Pro Forma Reserve and Operating Data

The following tables present summary data with respect to our estimated historical and pro forma net proved oil and natural gas reserves and operating data as of the dates presented.

The reserve estimates presented in the table below are based on our reserve report audited by NSAI, our independent reserve engineers, and with respect to the Beta properties, on the reserve report prepared by NSAI. Regarding our properties, estimates comprising approximately 97% of the total proved reserves in our reserve report were prepared by NSAI and the remaining portion was prepared by our internal reserve engineers. 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 “Business and Properties Overview” as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business—Our Oil and Natural Gas Data—Estimated Proved Reserves” included in our Annual Report on Form 10-K for the year ended December 31, 2011 and our Current Report on Form 8-K filed with the SEC on November 20, 2012, each of which is incorporated by reference herein, and the reserve reports included in this prospectus in evaluating the material presented below. The summaries of our reserve report and the reserve report with respect to the Beta properties are included as Appendices B and C, respectively, of this prospectus.

Reserve Data

 

     As of September 30, 2012  
     Memorial Production
Partners LP
Historical
    Beta Properties
Historical
    Memorial Production
Partners LP
Pro Forma Combined
 

Estimated Proved Reserves

      

Oil (MMBbls)

     4.7        14.3        19.0   

NGLs (MMBbls)

     16.7               16.7   

Natural gas (Bcf)

     384.8               384.8   
  

 

 

   

 

 

   

 

 

 

Total (Bcfe) (1)

     513.3        86.0        599.3   

Proved developed (Bcfe)

     305.9        59.8        365.7   

Proved undeveloped (Bcfe)

     207.4        26.2        233.6   

Proved developed reserves as a percentage of total proved reserves

     60     70     61

Standardized measure (in millions) (2)

   $ 427.3      $ 392.8      $ 820.1   

Oil and Natural Gas Prices (3)

      

Oil—NYMEX—WTI per Bbl

   $ 93.78      $ 105.44      $ 99.88   

Natural gas—NYMEX—Henry Hub per MMBtu

   $ 2.82      $      $ 2.82   

 

(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 depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%.

 

 

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  Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions. For a description of our commodity derivative contracts, please read “Business and Properties Overview—Operations—Derivative Activities” as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Commodity Derivative Contracts” included in our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2012 and our Current Report on Form 8-K filed with the SEC on November 20, 2012, each of which is incorporated by reference herein.
(3) Our estimated net proved reserves and related standardized measure were determined using 12-month average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month in effect as of the date of the estimate, 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. The unweighted average of the first-day-of-the-month prices for each of the twelve months ending September 30, 2012 were $91.48/Bbl for oil and $2.83/MMBtu for natural gas.

Operating Data

 

    Year Ended December 31, 2011     Nine Months
Ended September 30, 2012
 
    Memorial
Production
Partners LP
Historical (2)
    Beta
Properties
Historical
    Memorial
Production
Partners LP
Pro Forma
Combined (3)
    Memorial
Production
Partners LP
Historical (2)
    Beta
Properties
Historical
    Memorial
Production
Partners LP
Pro Forma
Combined (3)
 

Production and operating data:

           

Net production volumes:

           

Oil (MBbls)

    97        591        858        105        431        619   

NGLs (MBbls)

    182               299        236               254   

Natural gas (MMcf)

    15,936               22,894        13,242               16,631   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total (MMcfe)

    17,608        3,547        29,836        15,288        2,587        21,868   

Average net production (MMcfe/d)

    48.2        9.7        81.7        55.8        9.4        79.8   

Average sales price: (1)

           

Oil (per Bbl)

  $ 91.43      $ 102.74      $ 100.00      $ 95.77      $ 104.45      $ 102.52   

NGLs (per Bbl)

  $ 51.70      $      $ 50.46      $ 36.94      $      $ 37.59   

Natural gas (per Mcf)

  $ 4.13      $      $ 4.07      $ 2.72      $      $ 2.87   

Average price per Mcfe

  $ 4.77      $ 17.12      $ 6.50      $ 3.58      $ 17.41      $ 5.52   

Average unit costs per Mcfe:

           

Lease operating expenses

  $ 1.39      $ 5.64      $ 1.67      $ 1.25      $ 5.98      $ 1.69   

Production taxes

  $ 0.27      $      $ 0.29      $ 0.34      $      $ 0.30   

General and administrative expenses

  $ 0.59      $ 1.18      $ 0.48      $ 0.45      $ 1.22      $ 0.46   

Depletion, depreciation and amortization

  $ 1.71      $ 1.46      $ 1.62      $ 1.54      $ 1.57      $ 1.56   

 

(1) Prices do not include the effects of derivative cash settlements.
(2) Includes data with respect to the properties acquired from Memorial Resource in April and May 2012, which acquisitions were accounted for as transactions between entities under common control, similar to a pooling of interests.
(3) Includes data with respect to the Beta properties, as wells as the properties we acquired from third parties in 2011 and 2012.

 

 

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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, or incorporated by reference into, this prospectus in evaluating an investment in our common units. If any of these risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we may 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:

 

  Ÿ  

the amount of oil, natural gas and NGLs we produce;

 

  Ÿ  

the prices at which we sell our oil, natural gas and NGL production;

 

  Ÿ  

the amount and timing of settlements of our commodity derivatives;

 

  Ÿ  

the level of our operating costs, including maintenance capital expenditures and payments to our general partner and its affiliates; and

 

  Ÿ  

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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Current Report on Form 8-K filed with the SEC on November 20, 2012, which is incorporated by reference herein.

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

 

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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 producing 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.

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 revolving credit facility decreases, or our revenues decrease, as a result of lower oil or natural gas prices or for any other reason, we may not be able to obtain the capital necessary to sustain our operations at the expected levels necessary to generate cash sufficient to make distributions to our unitholders.

A decline in, or sustained low levels of, 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, 2011, the NYMEX-WTI oil future price ranged from a high of $145.29 per Bbl to a low of $33.87 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $13.58 per MMBtu to a low of $2.51 per MMBtu. From January 1, 2012 to September 30, 2012, the NYMEX-WTI oil future price ranged from a high of $110.55 per Bbl to a low of $77.28 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $3.30 per MMBtu to a low of $1.90 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.

Domestic natural gas prices have recently been at relatively historic low levels due to an oversupply of natural gas in the United States. If natural gas prices remain at these low levels for a sustained period, our cash flow and revenues will be affected, and we may not be able to continue paying distributions to our unitholders.

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 prices, or sustained lower 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

 

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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 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.

We intend to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved reserves over a three-to-six year period at any given point in time. These commodity derivative contracts include natural gas, oil and NGL financial swaps and collar contracts and natural gas basis financial swaps. The prices and quantities 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.

Our hedging transactions 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 or other unforeseen events 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

 

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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 pro forma estimated proved reserves as of September 30, 2012, excluding the effects of our commodity derivative contracts, would have decreased by $259.7 million, from $820.1 million to $560.4 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 unweighted 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 Financial Accounting Standards Board, or FASB, in 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. 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:

 

  Ÿ  

high costs, shortages or delivery delays of rigs, equipment, labor or other services;

 

  Ÿ  

composition of sour natural gas, including sulfur, carbon dioxide and other diluent content;

 

  Ÿ  

unexpected operational events and conditions;

 

  Ÿ  

failure of down hole equipment and tubulars;

 

  Ÿ  

loss of wellbore mechanical integrity;

 

  Ÿ  

failure of unavailability of gathering pipeline capacity, particularly from the Beta properties;

 

  Ÿ  

hydrocarbon or oilfield chemical spills;

 

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  Ÿ  

adverse weather conditions and natural disasters;

 

  Ÿ  

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;

 

  Ÿ  

loss of drilling fluid circulation;

 

  Ÿ  

fires, blowouts, surface craterings and explosions; and

 

  Ÿ  

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. Furthermore, the Beta properties, which we will acquire at the closing of this offering, are offshore Southern California. Development and production of oil and natural gas in offshore waters has inherent and historically higher risk than similar activities onshore.

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.

 

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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 our 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:

 

  Ÿ  

unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with their owners;

 

  Ÿ  

unable to obtain financing for such acquisitions on economically acceptable terms; or

 

  Ÿ  

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, including the Beta acquisition, 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, including the Beta acquisition, involves potential risks, including, among other things:

 

  Ÿ  

the validity of our assumptions about estimated proved reserves, future production, revenues, capital expenditures, operating expenses and costs;

 

  Ÿ  

an inability to successfully integrate the assets or businesses we acquire;

 

  Ÿ  

a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

 

  Ÿ  

a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

 

  Ÿ  

the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

 

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mistaken assumptions about the overall cost of equity or debt;

 

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  Ÿ  

potential lack of operating experience in the geographic market where the acquired assets or business are located;

 

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an inability to hire, train or retain qualified personnel to manage and operate our growing assets and business; and

 

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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.

The Beta properties are located in an area where we have not historically conducted operations, which exposes us to additional risk.

The Beta properties will be our first assets located offshore or in California. Because we do not have extensive experience in this geographic region, we are less able to use past operational results to help predict future results. Our lack of experience may result in our not being able to fully execute our expected production and drilling programs in this region, and the return on our investment in the Beta properties may not meet our expectations. We cannot assure you that our acquisition of the Beta properties will achieve the results that we currently anticipate. As a result, our business, results of operations, financial condition and ability to pay distributions to our unitholders may be affected.

Adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.

Our properties are located in Texas and Louisiana, and upon consummation of the Beta acquisition, offshore Southern California. 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 or in our ability to comply with local regulations, could have an impact on our results of operations and cash available for distribution to our unitholders.

We are dependent upon a small number of significant customers for a substantial portion of our production sales and we may experience a temporary decline in revenues and production if we lose any of those customers.

We had one individual customer that accounted for 10% or more of total reported revenues for the nine months ended September 30, 2012. To the extent this significant customer reduces the volume it purchases from us, we could experience a temporary interruption in sales of, or may receive a lower price for, our production, and our revenues and cash available for distribution could decline, which could adversely affect our ability to make cash distributions to our unitholders at the then-current distribution rate or at all.

 

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Additionally, a failure by this significant customer, or any purchaser of our production, to perform their payment obligations to us could have a material adverse effect on our results of operations. 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 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 handles sales of our natural gas, oil and NGL production on our behalf, which depends upon the demand for natural gas, oil and NGLs from potential 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.

 

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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 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 revolving credit facility has restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.

The operating and financial restrictions and covenants in our revolving credit facility and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions to our unitholders. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Current Report on Form 8-K filed with the SEC on November 20, 2012, which is incorporated by reference herein. Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our revolving credit facility that are not cured or waived within the appropriate time periods provided in our revolving credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions to our unitholders will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our revolving credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our revolving credit facility, the lenders could seek to foreclose on our assets.

Our revolving credit facility allows 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 is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated natural gas, oil and NGL reserves, which takes 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 at that time and, in such case, we could be required to repay any indebtedness outstanding 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 operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

There are a variety of operating risks inherent in our oil and natural gas properties and other assets, such as leaks, explosions, mechanical problems and natural disasters, all of which could cause substantial financial losses. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life,

 

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significant damage to property, environmental pollution, impairment of our operations and substantial revenue losses. The location of our oil and natural gas properties and other assets near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. Upon consummation of the Beta acquisition, our offshore operations will be subject to a variety of operating risks specific to the marine environment, such as a dependence on a limited number of electrical transmission lines, as well as capsizing, collisions and damage or loss from adverse weather conditions. Offshore activities are subject to more extensive governmental regulation than our other oil and natural gas activities. Upon consummation of the Beta acquisition, we will be vulnerable to the risks associated with operating offshore California, including risks relating to:

 

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natural disasters such as earthquakes, mudslides, fires and floods;

 

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oil field service costs and availability;

 

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compliance with environmental and other laws and regulations;

 

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remediation and other costs resulting from oil spill releases of hazardous materials and other environmental damages; and

 

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failure of equipment or facilities.

In addition to lost production and increased costs, these hazards could cause serious injuries, fatalities, contamination or property damage for which we could be held responsible. The potential consequences of these hazards are particularly severe for us because a significant portion of our offshore operations upon consummation of the Beta acquisition will be conducted in environmentally sensitive areas, including areas with significant residential populations. An accidental oil spill or release on or related to offshore properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. If an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and damages could be material to our business, financial condition or results of operations and could subject us to criminal and civil penalties. Finally, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation and development operations to be curtailed while those activities are being completed.

Insurance against all operational risk is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets due to weather and adverse economic conditions have made it more difficult for us to obtain certain types of coverage. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and we cannot be sure the insurance coverage we do obtain will contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders.

 

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Our business depends in part on pipelines, gathering systems and processing facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and natural gas production.

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. For example, our ability to produce and sell oil from the Beta properties will depend on the availability of the San Pedro Bay pipeline for delivery of that oil to shore. 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 with only 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 our properties, and to some extent the marketing of our production, is dependent upon the ability of the operators of our properties. Memorial Resource operates substantially all of our properties, either directly as operator or, where we are the operator of record, on our behalf. As of September 30, 2012, based on proved reserve volumes, we operated 67%, Memorial Resource operated 28% and third parties operated 5% 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:

 

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the nature and timing of drilling and operational activities;

 

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the timing and amount of capital expenditures;

 

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Memorial Resource’s or the operators’ expertise and financial resources;

 

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the approval of other participants in such properties; and

 

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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 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

 

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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, including, upon consummation of the Beta acquisition, those in California, vested with broad authority relating to the exploration for, and the development, production and transportation of, oil and natural gas, as well as environmental and safety matters. 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, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, the issuance of orders limiting or prohibiting some or all of our operations. Please read “Business—Environmental Matters and Regulation” and “Business—Other Regulation of the Oil and Natural Gas Industry” included in our Annual Report on Form 10-K for the year ended December 31, 2011, which is incorporated by reference herein, for a description of the laws and regulations that affect us. 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 owned or 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

 

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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.

Upon completion of the Beta acquisition, we will hold our first federal offshore leases. Federal offshore leases are administered by Bureau of Ocean Energy Management, or BOEM. Holders of federal offshore leases require compliance with detailed BOEM regulations, Bureau of Safety and Environmental Enforcement, or BSEE, regulations and the Outer Continental Shelf Lands Act (OCSLA), which are subject to interpretation and change. Lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard and the EPA. BSEE has regulations requiring offshore production facilities and pipelines located on the outer continental shelf to meet stringent engineering and construction specifications, and has proposed and/or promulgated additional safety related regulations concerning the design and operating procedures of these facilities and pipelines, including regulations to safeguard against or respond to well blowouts and other catastrophes. BSEE regulations also restrict the flaring or venting of natural gas and prohibit the flaring of liquid hydrocarbons and oil without prior authorization.

BSEE has regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities. BSEE generally requires that lessees either have substantial net worth, post supplemental bonds or provide other acceptable assurances that the obligations will be met. If we fail to pay royalties or comply with safety and environmental regulations, BOEM and BSEE may require that our operations on the Beta properties (which are on federal leases) be suspended or terminated. The requirements imposed by BOEM and BSEE regulations are frequently changed and subject to new interpretations.

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,” or GHGs, including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere and other climatic changes. The U.S. Congress has previously considered legislation to comprehensively address global climate change. For example, in June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, which would have required an 80% reduction in emissions of GHGs from sources within the U.S. between 2012 and 2050, but it 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.

 

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In addition, in December 2009, the U.S. Environmental Protection Agency, or 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. The motor vehicle rule, which was finalized in April 2010 and became effective in January 2011, purports to limit emissions of GHGs from motor vehicles manufactured in model years 2012-2016; however, it does not require immediate reductions in GHG emissions. A recent rulemaking proposal by the EPA and the Department of Transportation’s National Highway Traffic Safety Administration seeks to expand the motor vehicle rule to include vehicles manufactured in model years 2017-2025. The EPA adopted the stationary source rule (or the “tailoring rule”) in May 2010, and it also became effective January 2011, although it remains the subject of several pending lawsuits filed by industry groups. The tailoring rule establishes new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. The permitting requirements of the PSD program apply only to newly constructed or modified major sources. Obtaining a PSD permit requires a source to install best available control technology, or BACT, for those regulated pollutants that are emitted in certain quantities. Phase I of the tailoring rule, which became effective on January 2, 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the tailoring rule, which became effective on July 1, 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions by more than 75,000 tons per year. Phase III of the tailoring rule, which is expected to go into effect in 2013, will seek to streamline the permitting process and permanently exclude smaller sources from the permitting process. Finally, in October 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. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. On March 27, 2012, the EPA issued a proposed rule establishing carbon pollution standards for new fossil-fuel-fired electric utility generating units. The proposed rule underwent an extended public comment process, which concluded on June 25, 2012. The EPA is also under a legal obligation pursuant to a consent decree with certain environmental groups to issue new source performance standards for refineries.

In addition, many states have developed measures to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissions inventories and/or regional greenhouse gas cap and trade programs. In California, for example Assembly Bill 32 requires the California Air Resources Board, or CARB, to establish and adopt regulations by 2012 that will achieve an overall reduction in greenhouse gas emissions from all sources in California of 25% by 2020. In October 2011, the CARB adopted the final cap and trade regulation, including a delay in the start of the cap and trade rule’s compliance obligations until 2013. Because our operations emit greenhouse gases, upon consummation of the Beta acquisition, our operations in California may be subject to regulations issued under Assembly Bill 32. These regulations will increase our costs for those operations and adversely affect our operating results. The EPA has also adopted regulations imposing permitting and best available control technology requirements on the largest greenhouse gas stationary sources, regulations requiring reporting of greenhouse gas emissions from certain facilities, and it is considering additional regulation of greenhouse gases as

 

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“air pollutants” under the existing federal Clean Air Act. Passage of climate change legislation or other regulatory initiatives by Congress or various states, or the adoption of regulations by the EPA or analogous state agencies, that regulate or restrict emissions of greenhouse gases (including methane or carbon dioxide) in areas in which we conduct business could have an adverse effect on our operations and the demand for oil and natural gas.

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—Environmental Matters and Regulation” and “—Other Regulation of the Oil and Natural Gas Industry” included in our Annual Report on Form 10-K for the year ended December 31, 2011, which is incorporated by reference herein, for a description of the laws and regulations that affect us.

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 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—Environmental Matters and Regulation” and “—Other Regulation of the Oil and Natural Gas Industry” included in our Annual Report on Form 10-K for the year ended December 31, 2011, which is incorporated by reference herein, for a description of the laws and regulations that affect the third parties on whom we rely.

Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.

The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act, or 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. Although many of the rules necessary to implement the Act remain to be adopted, the CFTC has issued a large number of rules to implement the Act, including a rule establishing an “end-user” exception to mandatory clearing, referred to herein as the “End-User Exception,” and a rule imposing position limits, referred to herein as the Position Limit Rule.

We qualify as a “non-financial entity” for purposes of the End-User Exception and, as such, we will be eligible for and expect to utilize such exception and, as a result, our hedging activity

 

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will not be subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing. However, most if not all of our hedge counterparties will be subject to mandatory clearing in connection with their hedging activities with parties who do not qualify for the End-User Exception. The Position Limit Rule was vacated and remanded to the CFTC for further proceedings by order of the United States District Court for the District of Columbia, U.S. District Judge Robert L. Wilkins on September 28, 2012. The Act, the rules which have been adopted and not vacated, and, to the extent that a position limit rule is ultimately effected, such position limit rule 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.

Our operations in offshore Southern California could be adversely impacted by the Macondo accident and resulting oil spill.

Upon consummation of the Beta acquisition, we will have offshore Southern California development and production operations. While the six-month moratorium on the drilling of new deepwater wells and a suspension of permitted wells being drilled in the Outer Continental Shelf regions of the Gulf of Mexico and Pacific Ocean was conditionally lifted in October 2010, permits are currently being issued at a much slower rate than before the Macondo accident. The BOEM and BSEE are expected to issue additional governmental regulation of the offshore exploration and production industry. Recent legislative proposals include limitations upon, or elimination of, existing liability caps, an increased minimum level of financial responsibility and additional safety and spill-response requirements. We cannot predict with any certainty what form the additional regulation or limitations will take. The impact upon our business of such regulations or limitations could include cost increases, offshore exploration and development activity delay, as well as changes in the availability and cost of insurance.

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 a final guidance document 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 and the public of certain information regarding the components, as well as the volume of water, used in the hydraulic fracturing process. This public disclosure requirement became effective on February 1, 2012. In addition to state law, local land use restrictions, such as city ordinances, may

 

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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.

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 an interim report 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, on May 4, 2012, the U.S. Department of Interior issued a draft rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm its wells meet certain construction standards and (iii) establish site plans to manage flowback water.

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 shale formations 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.

On April 17, 2012, the EPA issued a final rule that subjects oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAP, programs. The EPA’s final rule includes NSPS standards for completions of hydraulically fractured wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule is described in more detail below.

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

 

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pretreatment rules will require shale gas operations to pretreat wastewater before transferring it to treatment facilities. Proposed rules are expected in 2013 for coalbed methane and 2014 for shale gas.

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 April 17, 2012, the EPA issued a final rule that subjects oil and natural gas production, processing, transmission, and storage operations to regulation under the NSPS and NESHAP programs. The EPA’s final rule includes NSPS standards for completions of hydraulically fractured wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule became effective October 15, 2012; however, a number of the requirements did not take immediate effect. The final rule establishes a phase-in period to allow for the manufacture and distribution of required emissions reduction technology. During the first phase, ending December 31, 2014, owners and operators must either flare their emissions or use emissions reduction technology called “green completions” technologies already deployed at wells. On or after January 1, 2015, all newly fractured wells will be required to use green completions. Controls for certain storage vessels and pneumatic controllers may phase-in over one year beginning on August 16, 2012, which is the date the final rule was published in the Federal Register, while certain compressors, dehydrators and other equipment must comply with the final rule immediately or up to three years and 60 days after publication of the final rule, depending on the construction date and/or nature of the unit. We continue to evaluate the EPA’s final rule, as it may require changes to our operations, including the installation of new emissions control equipment.

The cost of decommissioning is uncertain.

Upon consummation of the Beta acquisition, we will assume our proportionate share of decommissioning costs associated with the Beta properties. We will be required to maintain reserve funds to provide for the payment of our proportionate share of such decommissioning costs. The estimates of decommissioning costs are inherently imprecise and subject to change due to changing cost estimates, oil and natural gas prices and other factors. If actual decommissioning costs exceed such estimates, or we are required to provide a significant amount of collateral in cash or other security as a result of a revision to such estimates, our financial condition, results of operations and cash flows may be materially adversely affected.

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-

 

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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 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 has control over all decisions related to our operations. Memorial Resource owns 100% of the voting membership interests in our general partner and all of our subordinated units. Immediately following this offering and assuming the underwriters do not exercise their option to purchase additional common units, Memorial Resource will own approximately 25.7% of our outstanding common units. 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. For example, all of our directors other than the members of the conflicts committee of the board of directors of our general partner have indirect interests in the Funds that own the seller of the Beta properties. 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. Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies 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:

 

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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;

 

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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;

 

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  Ÿ  

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;

 

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except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

 

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many of the officers and directors of our general partner who provide services to us 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;

 

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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;

 

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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;

 

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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;

 

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we and our general partner have entered into an omnibus agreement with Memorial Resource, pursuant to which, among other things, Memorial Resource operates our assets and performs other management, administrative, and operating services for us and our general partner;

 

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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;

 

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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;

 

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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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  Ÿ  

our general partner decides whether to retain separate counsel, accountants, or others to perform services for us;

 

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our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations;

 

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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;

 

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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;

 

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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; and

 

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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.

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 are not 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 rely solely on the employees of Memorial Resource to manage our business. The management team of Memorial Resource also performs substantially similar services for Memorial Resource, which owns and operates its own assets, and thus will not be solely focused on our business.

Neither we nor our general partner have any employees and we rely solely on Memorial Resource to operate our assets. We and our general partner have entered into an omnibus agreement with Memorial Resource, pursuant to which, among other things, Memorial Resource agreed to operate our assets and perform other management, administrative, and operating services for us and our general partner.

 

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Memorial Resource provides substantially similar activities with respect to its own assets and operations. Because Memorial Resource provides 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 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.

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 spend significant time serving, entities that may 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 natural 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 before our initial public offering and is now a venture partner with NGP and continues to hold ownership interests in the Funds and certain of their affiliates. 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

 

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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 or other duties that are in conflict with the 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 those opportunities 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 “Certain Relationships and Related Party Transactions” 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 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.

We have entered 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 agreements include the following:

 

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an omnibus agreement pursuant to which, among other things, Memorial Resource provides management, administrative and operating services for us and our general partner; and

 

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a tax sharing agreement pursuant to which we 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 is included in a combined or consolidated tax return with Memorial Resource or its applicable affiliate(s).

 

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Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Our 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 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.

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

 

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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, has 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 is 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 has control over all decisions related to our operations. Since immediately following this offering Memorial Resource will own our general partner, approximately 25.7% 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 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 has 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.”

 

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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 the conflicts committee of the board of directors of our general partner 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:

 

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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 our partnership agreement;

 

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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;

 

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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 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;

 

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  Ÿ  

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

 

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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 our partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and 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 owns sufficient units to be able to prevent our general partner’s removal. The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove our general partner. Immediately following this offering, Memorial Resource will own our general partner, approximately 25.7% of our outstanding common units, and all of our subordinated units, which together will constitute approximately 37.8% of all outstanding 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.

A default under Memorial Resource’s credit facility could result in a change of ownership or control of our general partner or us, which would be an event of default under our revolving credit facility.

Memorial Resource has pledged all of its common units and subordinated units in us, as well as its ownership interest in our general partner, as security under its senior secured revolving credit facility. That credit facility contains customary and other events of default relating to defaults of Memorial Resource. As a result, our ownership is subject to change if Memorial

 

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Resource were to default under its credit facility and Memorial Resource’s lenders exercise their rights over the pledged collateral, even if we do not have any borrowings outstanding under that credit facility. A change of control would constitute an event of default under our revolving credit facility and could affect the market price of our common units.

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.

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:

 

  Ÿ  

our unitholders’ proportionate ownership interest in us will decrease;

 

  Ÿ  

the amount of cash available for distribution on each unit may decrease;

 

  Ÿ  

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;

 

  Ÿ  

the ratio of taxable income to distributions may increase;

 

  Ÿ  

the relative voting strength of each previously outstanding unit may be diminished; and

 

  Ÿ  

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.

 

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Memorial Resource may sell common units, which sales could have an adverse impact on the trading price of the common units.

Immediately following this offering, Memorial Resource will own approximately 25.7% of our outstanding common units and all of our subordinated units, which convert into common units at the end of the subordination period. Sales by Memorial Resource of a substantial number of our common units, including common units issued upon the conversion of the subordinated units, 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 further capital through additional offerings of equity securities.

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 current market price as of 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. Immediately following this offering, Memorial Resource will own approximately 25.7% 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.”

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, 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.

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. 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.”

 

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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:

 

  Ÿ  

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

 

  Ÿ  

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.

We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions, and covenants in our 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 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 revolving credit facility 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

 

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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:

 

  Ÿ  

general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds;

 

  Ÿ  

conditions in the oil and natural gas industry;

 

  Ÿ  

the market price of, and demand for, our common units;

 

  Ÿ  

our results of operations and financial condition; and

 

  Ÿ  

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.

Our common units are listed on NASDAQ. Because we are 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 do not have the same protections afforded to certain corporations that are subject to all of NASDAQ corporate governance requirements.

Tax Risks to Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation, 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, nor do we plan to request, a ruling from the IRS on this or any other tax matter affecting us.

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. Although we do not believe based on our current operations that we are so treated, 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 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

 

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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.

Legislation has been proposed 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, 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

 

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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.

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

 

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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 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 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.

 

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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 currently own property and conduct business in Texas and Louisiana. Upon consummation of the Beta acquisition, we will own property and conduct business in California. Louisiana and California currently impose a personal income tax on individuals. These states also impose an income or franchise 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 expect to receive approximately $         million in net proceeds from the sale of the common units we are offering hereby, or $         million in net proceeds if the underwriters exercise in full their option to purchase additional common units, in each case including our general partner’s proportionate capital contribution and after deducting underwriting discounts but before estimated offering expenses. We intend to use the net proceeds of approximately $         million from our sale of common units in this offering to fund a portion of the approximate $271 million purchase price, which includes $3 million of working capital and other customary adjustments, for the Beta acquisition, which will close simultaneously with the closing of this offering. The closing of the Beta acquisition is not contingent on the completion of this offering. Please read “Beta Acquisition.”

The following table illustrates our use of the net proceeds of this offering and our borrowings under our revolving credit facility if the Beta acquisition is consummated.

 

Sources of Cash (In millions)

    

Uses of Cash (In millions)

 

Gross proceeds from this offering (1)

   $                    Beta acquisition    $                

Borrowings under our revolving credit facility to fund the Beta acquisition (1)

     

Underwriting discounts, transaction fees and other offering fees and expenses payable by us

  
  

 

 

       

 

 

 

Total

   $                    Total    $                
  

 

 

       

 

 

 

 

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

We have the option to pay a portion of the purchase price for the Beta acquisition, up to $162 million, by executing and delivering promissory notes payable to the seller. To the extent the net proceeds of this offering are less than $150 million, we will pay the seller a cash amount equal to those net proceeds plus borrowings of $121 million under our revolving credit facility, and the remainder of the purchase price will be the aggregate principal amount of promissory notes payable to the seller. Please read “Beta Acquisition” for more information regarding those promissory notes.

If the underwriters exercise their option to purchase additional common units at any time after the closing of the Beta acquisition, we will use the net proceeds of that exercise for general partnership purposes.

 

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CAPITALIZATION

The following table sets forth our capitalization as of September 30, 2012:

 

  Ÿ  

on an actual basis; and

 

  Ÿ  

on an as adjusted basis to give effect to the Beta acquisition and the issuance and sale of common units in this offering and our general partner’s proportionate capital contribution, assuming no exercise of the underwriters’ option to purchase additional common units, and the application of the net proceeds from this offering and from borrowings under our revolving credit facility 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 consolidated financial statements and the accompanying notes incorporated by reference in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2012, which is incorporated by reference herein, and “Use of Proceeds.”

 

     As of September 30, 2012  
     Actual      As Adjusted  
     (In thousands)  
     (Unaudited)  

Long-term debt (1)

   $ 293,000       $                

Partners’ capital/net equity:

     

Common units held by public

     148,275      

Common units held by Memorial Resource

     75,400      

Subordinated units held by Memorial Resource

     57,242      

General partner interest

     398      
  

 

 

    

 

 

 

Total partners’ capital/net equity

     281,315      
  

 

 

    

 

 

 

Total capitalization

   $ 574,315       $                
  

 

 

    

 

 

 

 

(1) We currently expect to fund a portion of the approximate $271 million purchase price, which includes $3 million of working capital and other customary adjustments, for the Beta acquisition using borrowings under our revolving credit facility.

This table does not reflect the issuance of up to an additional 1,575,000 common units that may be sold to the underwriters upon exercise of their option to purchase additional common units.

 

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BETA ACQUISITION

Overview of Acquisition

On November 19, 2012, we, through a wholly-owned subsidiary, entered into a purchase and sale agreement pursuant to which we agreed to purchase all of the outstanding equity interests in Rise Energy Operating, LLC and its subsidiaries, which collectively own certain oil and gas producing properties and assets offshore Southern California, for approximately $271 million, including $3 million of working capital and other customary adjustments. We refer to this transaction as the “Beta acquisition” and the properties and assets to be acquired as the “Beta properties.” The Beta acquisition will close simultaneously with the completion of this offering.

The Beta properties were first discovered in 1976 by Royal Dutch Shell PLC and have been in production since January 1981. As of September 30, 2012, the total estimated proved reserves attributable to the Beta properties were approximately 14.3 MMBbls, based on the reserve report prepared by NSAI, of which approximately 100% were oil and approximately 70% were classified as proved developed reserves, with a standardized measure of $392.8 million. The average net production associated with the Beta properties for the nine months ended September 30, 2012 was 1,574 Bbls/d, implying a reserve-to-production ratio of 24.9 years. The total estimated proved reserves attributable to the Beta properties at September 30, 2012 were determined using index prices for oil and natural gas, without giving effect to derivative transactions. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $91.48/Bbl for oil and $2.83/MMBtu for natural gas.

We expect to finance the Beta acquisition with cash on hand, borrowings under our revolving credit facility, the net proceeds from this offering and, potentially, promissory notes payable to the seller. The closing of the Beta acquisition is not contingent on the completion of this offering, and we have the option to pay the entire purchase price with borrowings under our revolving credit facility and promissory notes payable to the seller. In connection with the completion of the Beta acquisition, we have secured commitments from our lenders to increase the current borrowing base under our revolving credit facility from $380 million to $460 million. Please read “—Purchase and Sale Agreement and Seller Note” for more information about the promissory notes to the seller and “Use of Proceeds” for more information about the application of the net proceeds from this offering.

The seller of the Beta properties is primarily owned by two of the Funds; because this is a related party transaction, the conflicts committee of the board of directors of our general partner reviewed the Beta acquisition and the terms of the related transactions and agreements, engaged and consulted with its independent financial and legal advisors with respect thereto, granted “special approval” with respect to the Beta acquisition pursuant to our limited partnership agreement. Based upon that special approval, and upon the recommendation of the conflicts committee, the board of directors of our general partner also approved the Beta acquisition. Please read “Conflicts of Interest and Fiduciary Duties” and “Certain Relationships and Related Party Transactions—Related Party Agreements—Acquisitions of Oil and Natural Gas Producing Properties.”

Reasons for Acquisition

The Beta acquisition complements our existing properties because:

 

  Ÿ  

the assets exhibit a stable long-lived production profile with an estimated average annual proved developed producing decline rate of approximately 5%;

 

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  Ÿ  

the assets have a diverse distribution of reserve value, with 51 gross (26 net) producing wells, none of which contains in excess of 5% of the total estimated proved reserves attributable to the Beta properties;

 

  Ÿ  

the assets have relatively high operating margins and moderate capital expenditure requirements;

 

  Ÿ  

the assets present multiple low-cost development opportunities to us such as injection enhancement, drilling, and recompletion opportunities and include 4.4 MMBbls of estimated proved undeveloped reserves, which we expect, in conjunction with the appropriately-sized platforms and production facilities, will allow for lower-cost and lower-risk growth;

 

  Ÿ  

the acquisition will further diversify both our asset mix, by adding a significant amount of oil, and our geographic basins;

 

  Ÿ  

we expect that reservoir injection enhancement programs, which replace the loss of reservoir pressure, could significantly increase future production and reserves from these properties;

 

  Ÿ  

Memorial Resource expects to retain substantially all of the operating personnel managing the Beta properties, which we expect will allow for seamless operations and permit us to take advantage of such personnel’s significant experience with and knowledge of the assets as well as the California operating and regulatory environment;

 

  Ÿ  

we will be the operator of the Beta properties, which we expect will allow us to manage operating costs and better control capital expenditures, as well as the timing of development activities; and

 

  Ÿ  

we expect to benefit from oil prices determined using the Midway-Sunset benchmark, which currently receive premium pricing to WTI crude.

Beta Field

The Beta Field is one of the most established oil fields located offshore Southern California, with over 30 years of production history and an estimated proved developed producing decline rate of approximately 5%. The Beta Field was placed into production in 1981 with production peaking at approximately 18,900 Bbls per day in 1987.

Beta Properties

Overview

The Beta properties consist of: (i) a 51.75% working interest and a 35.03% average net revenue interest in three Pacific Outer Continental Shelf blocks (P-0300, P-0301 and P-0306), referred to as the Beta unit, in the Beta Field located in federal waters approximately 11 miles offshore the Port of Long Beach, California; (ii) a 4.575% overriding royalty interest in the Beta unit; (iii) a 51.75% undivided interest in (a) two wellbore production platforms with permanent drilling equipment systems and (b) one production handling and processing platform; and (iv) a 51.75% controlling equity interest in a 17.5-mile pipeline and an onshore tankage and metering facility.

 

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Beta Unit and Platforms

The Beta properties include a 51.75% undivided interest in two wellbore production platforms, referred to as the Ellen and Eureka platforms, with permanent drilling equipment systems and a 51.75% undivided interest in one production handling and processing platform, referred to as the Elly platform. The Ellen platform is located in block P-0300 in the Beta Field and currently has 80 well slots. The Eureka platform is located in block P-0301 in the Beta Field and currently has 60 well slots. We believe there are over 50 available well slots for additional production and injection wells for the Ellen and Eureka platforms. Royal Dutch Shell PLC installed the platforms in the 1980s, and production from the Ellen and Eureka platforms commenced in January 1981 and March 1985, respectively. The Beta unit was formed in 1983. The Elly platform, which is bridge connected to the Ellen platform, handles production and processing for the Ellen and Eureka platforms as well as metering and sales connectivity for a third-party platform.

Pipeline and Onshore Production Equipment

The Beta properties include a controlling interest in the San Pedro Bay pipeline, a 16-inch diameter oil pipeline that extends approximately 17.5 miles from the Elly platform to the Beta pump station located onshore at the Port of Long Beach, California. The pipeline currently handles approximately 4,100 Bbls/d from the Ellen and Eureka platforms as well as approximately 400 Bbl/d from a third-party platform. Crude oil delivered to the Beta pump station is metered and received into a 10,000 Bbl storage tank. The pipeline includes two pipelines that connect to two sales outlets that connect to the THUMS header, operated by Crimson Pipeline LP, that can deliver the crude oil to over five refineries. All of the crude oil produced from the Ellen and Eureka platforms is currently being delivered to one refinery under a short-term evergreen marketing agreement.

Hedging

As part of the Beta acquisition, we will acquire crude oil hedges from the closing of the acquisition through 2015. The acquired hedges will cover a significant portion of 2013 crude oil volumes as well as volumes in 2014 and 2015. In addition to the acquired hedges and consistent with our hedging policy, we entered into additional crude oil hedges through 2017 that cover 65% to 85% of our targeted crude oil production per year. Please read “Business and Properties Overview—Operations—Derivative Activities.”

Purchase and Sale Agreement and Seller Note

Our acquisition of the Beta properties is governed by a purchase and sale agreement entered into on November 19, 2012 between our operating subsidiary and Rise Energy Partners, LP. Under that purchase and sale agreement, which is filed as exhibit 2.1 to our Current Report on Form 8-K filed on November 20, 2012 and is incorporated by reference into this document, we are obligated to close the Beta acquisition on December 27, 2012 or such earlier date as we and the seller agree. The closing of the Beta acquisition is not contingent on the closing of this offering; we and the seller have agreed to close the Beta acquisition simultaneously with the closing of this offering.

The purchase and sale agreement has customary representations, warranties and indemnities regarding the Beta properties and the transaction, most of which indemnification obligations are subject to a deductible of $5 million and a maximum indemnification amount of $26.8 million, which amount will be placed in an indemnity escrow account for one year and available for us to satisfy any indemnification claims made during that time.

 

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The purchase and sale agreement also provides us with the option to pay a portion of the purchase price, up to $162 million, by execution and delivery of one or more promissory notes payable to the seller, which we refer to as seller notes. To the extent the net proceeds of this offering are less than $150 million, we will pay the seller a cash amount equal to those net proceeds plus borrowings of $121 million under our revolving credit facility, and the remainder of the purchase price will be the aggregate principal amount of promissory notes payable to the seller. If we deliver a seller note, the amount of the purchase price paid into the indemnity escrow account will be reduced by the principal amount of the seller note, and we will have the right to set off any indemnity claims made during the first year against that seller note up to the maximum indemnification amount, and any prepayments made on that seller note in the first year after closing will be made into the indemnity escrow account.

Any seller note will have a maturity date of 16 months after the closing, and will initially bear interest at 8%, payable quarterly. If a seller note remains outstanding six months after the closing, the interest rate will increase to 12%. Any seller note will be expressly subordinated to our obligations under our revolving credit facility, and will have a cross-default provision with our revolving credit facility. In limited circumstances, we would be able to increase the principal amount of the seller note in lieu of paying interest for any quarter if payment of such interest would limit our ability to pay distributions to our unitholders at our current announced rate.

We would have the right to prepay the seller notes, subject to the terms of our revolving credit facility, in whole or in part at any time without penalty and would be required to repay the seller notes with the net proceeds of any debt or equity securities that we issue after the closing. The seller notes would include covenants that would restrict our ability to extend the maturity of our revolving credit facility or to incur additional debt senior to or pari passu with the seller notes, other than under our revolving credit facility.

 

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BUSINESS AND PROPERTIES OVERVIEW

The following Business and Properties Overview should be read in conjunction with the unaudited pro forma condensed combined financial statements and related notes and the historical financial statements and related notes of Memorial Production Partners LP and Rise Energy Operating, LLC incorporated by reference or included elsewhere in this prospectus. Please also read “Business” and “Properties” included in our Annual Report on Form 10-K for the year ended December 31, 2011, which is incorporated by reference herein. Unless otherwise indicated, all references to financial or operating data on a pro forma basis give effect to the transaction described under “Beta Acquisition” and in the unaudited pro forma condensed combined financial statements included elsewhere in this prospectus.

Our pro forma estimated proved reserve information as of September 30, 2012 is based on our reserve report audited by NSAI and the reserve report relating to the Beta properties prepared by NSAI.

Overview

We are a Delaware limited partnership formed in April 2011 by Memorial Resource to own, acquire and exploit 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. Our assets consist primarily of producing oil and natural gas properties and are principally located in Texas and Louisiana and, following completion of the Beta acquisition, offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs with well-known geologic characteristics and long-lived, predictable production profiles and modest capital requirements. As of September 30, 2012:

 

  Ÿ  

Our total pro forma estimated proved reserves were approximately 599 Bcfe, of which approximately 64% were natural gas and 61% were classified as proved developed reserves;

 

  Ÿ  

We produced from 1,667 gross (729 net) producing wells pro forma across our properties, with an average working interest of 44%, and we or Memorial Resource operated 95% of the properties in which we have interests; and

 

  Ÿ  

Our average pro forma net production for the nine months ended September 30, 2012 was 79.8 MMcfe/d, implying a reserve-to-production ratio of 20.6 years.

Since completing our initial public offering in December 2011, we have completed four acquisitions and will close the Beta acquisition simultaneously with the closing of this offering. After giving effect to these acquisitions, we have:

 

  Ÿ  

Diversified our commodity mix by adding significant oil and NGL rich assets, and expanded our geographic footprint;

 

  Ÿ  

Increased our average net production from 48.8 MMcfe/d for the year ended December 31, 2011 to 79.8 MMcfe/d pro forma for the nine months ended September 30, 2012;

 

  Ÿ  

Increased our estimated net proved reserves from 324 Bcfe as of December 31, 2011 to 599 Bcfe pro forma as of September 30, 2012; and

 

  Ÿ  

Increased our organic drilling and recompletion opportunities from 345 as of December 31, 2011 to 573 pro forma as of September 30, 2012.

 

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During that same period, we also increased our quarterly distribution rate from $0.4750 per unit to $0.4950 per unit, which represents an annualized distribution of $1.98 per unit and a 4.2% increase over the initial distribution.

Recent Developments

Distribution Rate Increase Announcement

On November 19, 2012, the board of directors of our general partner approved, subject to the completion of the Beta acquisition, an increase in our distribution rate attributable to the fourth quarter of 2012 to $0.5075 per unit, representing an annualized distribution of $2.03 per unit. This represents a 2.5% increase over our current annualized distribution of $1.98 per unit and a 6.8% increase over our initial annualized distribution of $1.90 per unit.

Other 2012 Acquisitions

We seek to acquire properties with long-lived reserves, low production decline rates and identified and predictable development potential. During 2012, we completed four acquisitions that met such criteria for an aggregate of $175.2 million. These acquisitions were consistent with our business strategies of utilizing our relationships with Memorial Resource and the Funds to acquire producing oil and natural gas properties from them that meet our acquisition criteria as well as to use such relationships to increase the size and scope of third-party acquisition targets we pursue. Two of our acquisitions were from Memorial Resource, one acquisition was made via a joint bid with Memorial Resource from an undisclosed third party, and the fourth acquisition was from a third party. Below is a summary of information relating to our 2012 acquisitions.

 

Date

 

Transaction Structure

  Average  Net
Production

MMcfe/d(1)
   

Location

  Net Aggregate
Purchase  Price

($ in millions)
 

September 2012

  Third-Party Acquisition     12.6      East Texas   $ 93.2   

May 2012

  Acquisition from Memorial Resource     4.2      East Texas     27.0   

May 2012

  Joint Bid Third-Party Acquisition with Memorial Resource     3.5      East Texas/North Louisiana     36.5   

April 2012

  Acquisition from Memorial Resource     2.3      East Texas     18.5   
   

 

 

     

 

 

 

Total

      22.6        $ 175.2   
   

 

 

     

 

 

 

 

(1) Estimated by management at the time of the respective acquisitions.

At September 30, 2012, these acquired properties contained 209 Bcfe of estimated proved reserves. In completing these acquisitions, we have increased our base of producing properties, increased our amount of total proved reserves and expanded our footprint within East Texas/North Louisiana. These acquisitions have also increased our ability to organically maintain or increase our production by contributing an additional 166 proved, low risk infill drilling, recompletion and development opportunities to our inventory. We expect to continue to exploit these opportunities to maintain our target production levels over time, as well as to continue evaluating additional acquisition opportunities.

 

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Our Properties

Our properties are located in South Texas and East Texas/North Louisiana and, after giving effect to the Beta acquisition, offshore Southern California and consist of large, mature 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, modest capital requirements and substantial opportunities for further exploitation and development. The following table sets forth certain information with regard to our estimated proved reserves and the estimated proved reserves attributable to the Beta properties at September 30, 2012, our pro forma estimated proved reserves as of September 30, 2012, and pro forma average net daily production for the nine months ended September 30, 2012.

 

Region

  Memorial
Production
Partners  LP

Historical
    Beta
Properties

Historical
    Memorial Production Partners LP
Pro Forma
 
  Estimated
Net Proved
Reserves
Bcfe (1)
    Estimated
Net Proved
Reserves
MMBbls
    Estimated Net Proved Reserves     Standardized
Measure (2)
(in millions)
    Average Net
Production
    Average
Reserve-to-

Production
Ratio (3)

(years)
    Producing
Wells
 
      Bcfe (1)     % Oil
and
NGL
    % Natural
Gas
    % Proved
Developed
      MMcfe/d     % of
Total
      Gross     Net  

South Texas

    176.1               176.1        14     86     84   $ 127.9        27.5        34     17.6        515        408   

East Texas/North Louisiana

    337.2               337.2        31     69     47     299.4        42.9        54     21.5        1,101        295   

California

           14.3        86.0        100     0     70     392.8        9.4        12     24.9        51        26   
 

 

 

   

 

 

   

 

 

         

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    513.3        14.3        599.3        36     64     61   $ 820.1        79.8        100     20.6        1,667        729   
 

 

 

   

 

 

   

 

 

         

 

 

   

 

 

   

 

 

     

 

 

   

 

 

 

 

(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 calculated in accordance with ASC Topic 932, Extractive Activities—Oil and Gas. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to commodity derivative contracts.
(3) The average reserve-to-production ratio is calculated by dividing our estimated pro forma net proved reserves as of September 30, 2012 by our annualized average pro forma net production for the nine months ended September 30, 2012.

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:

 

  Ÿ  

Maintain and grow a stable production profile through accretive acquisitions and lower-risk development. Our development plans target proved drilling locations with relatively low costs that support a stable production profile. We seek to acquire properties with long-lived reserves, low production decline rates and identified and predictable development potential. Since our initial public offering through the Beta acquisition, we have been able to grow our proved reserves 85% organically and through acquisitions. We believe that our management team’s experience positions us to identify, evaluate, execute, integrate and exploit suitable acquisitions.

 

  Ÿ  

Exploit opportunities on our current properties and manage our operating costs and capital expenditures. We intend to pursue low-risk drilling of our proved undeveloped inventory and to perform cost-reducing operational enhancements. Pursuant to an omnibus agreement, Memorial Resource provides us and our general partner with operating, management, and administrative services, which we believe provides us with significant technical expertise and experience that will

 

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allow us to identify and execute cost-reducing exploitation and operational improvements on both our existing properties and new acquisitions. Memorial Resource’s operational control of substantially all of our proved reserves as well as its own, often adjoining or complementary, properties enables direct influence and implementation of project scheduling and cost reduction initiatives.

 

  Ÿ  

Utilize our relationship with Memorial Resource, the Funds, and their respective affiliates (including NGP) to gain access to and, from time to time, acquire from them producing oil and natural gas properties that meet our acquisition criteria. We may have additional opportunities to acquire producing oil and natural gas properties directly from Memorial Resource, the Funds, or their respective affiliates from time to time in the future. We believe that selling properties to us will enhance Memorial Resource’s and, accordingly, the Funds’ economic returns by monetizing long-lived producing properties while potentially retaining a portion of the resulting cash flow through distributions on Memorial Resource’s (and the Funds’) limited partner and incentive distribution interests in us. However, none of Memorial Resource, the Funds, or any of their respective affiliates is contractually obligated to offer or sell any properties to us.

 

  Ÿ  

Leverage our relationships with Memorial Resource, the Funds, and their respective affiliates (including NGP) to participate with them in acquisitions of third party producing properties and to increase the size and scope of our potential third-party acquisition targets. We may have additional opportunities to work jointly with Memorial Resource to pursue certain acquisitions of oil and natural gas properties that may not otherwise be attractive acquisition candidates for either of us individually. Memorial Resource was formed in part to acquire and develop oil and natural gas properties, some of which will likely meet our acquisition criteria. In addition, NGP and its affiliates (including the Funds) have long histories of pursuing and consummating oil and natural gas property acquisitions in North America. Through our relationships with Memorial Resource, the Funds, and their respective affiliates (including NGP), we have access to their significant pool of management talent and industry relationships, which we believe provides us a competitive advantage in pursuing potential third-party acquisition opportunities. For example, we and Memorial Resource may jointly pursue an acquisition where we would acquire the proved developed portion of the acquired properties and Memorial Resource would acquire the undeveloped portion. We believe this arrangement gives us access to an array of third-party acquisition opportunities that we would not otherwise be in a position to pursue.

 

  Ÿ  

Reduce exposure to commodity price risk and stabilize cash flows through a disciplined commodity hedging policy. We intend to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved reserves over a three-to-six year period at any given point in time. These commodity derivative contracts include natural gas, oil and NGL financial swaps and collar contracts and natural gas basis financial swaps. We believe these commodity derivative contracts will allow us to mitigate the impact of oil and natural gas price volatility, thereby increasing the predictability of our cash flow.

 

  Ÿ  

Maintain reasonable levels of indebtedness to permit us to opportunistically finance acquisitions. We intend to maintain modest levels of indebtedness in relation to our cash flows from operations. We believe our internally generated cash flows, our access to capital markets through public and private equity and debt offerings and our borrowing capacity under our revolving credit facility will provide us with the financial flexibility to pursue our acquisition and development strategy in an effective and competitive manner.

 

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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:

 

  Ÿ  

Our diversified asset portfolio is characterized by long-lived reserves with low geologic risk, significant production history and predictable production decline rates. Our well life is typically more than 20 years, providing a long history of production that enables better predictability of future production decline rates. Our total pro forma estimated proved reserves had a reserve-to-production ratio of 20.6 years based on our average pro forma net production for the nine months ended September 30, 2012. Based on our reserve report and the reserve report with respect to the Beta properties, as of September 30, 2012, our pro forma estimated average proved developed producing decline rate per year is approximately 10% for the first three years, 7% for the next five years and 7% thereafter.

 

  Ÿ  

Our relationships with Memorial Resource, the Funds, and their respective affiliates (including NGP), which we believe (i) provide us with access to a portfolio of additional oil and natural gas properties that meet our acquisition criteria and (ii) helps us with access to and in the evaluation and execution of future acquisitions. Memorial Resource was formed in part to own and acquire producing properties and to develop properties into mature, long-lived producing assets. During 2012, we acquired two sets of producing properties from Memorial Resource and completed a joint acquisition of properties with Memorial Resource, and the seller of the Beta properties is primarily owned by two of the Funds. As of June 30, 2012, Memorial Resource had (i) total estimated proved reserves of over 1,235 Bcfe, primarily located in East Texas, North Louisiana and the Rockies and (ii) interests in over 579,570 gross (335,323 net) acres of properties. Based on Memorial Resource’s intention to develop its properties and Memorial Resource’s significant ownership interests in us, we believe we may be able to acquire additional assets from Memorial Resource, the Funds, or their respective affiliates in the future, although none of them have any obligation to offer or sell properties to us. Additionally, we believe that our ability to use the industry relationships and broad expertise of Memorial Resource and NGP in expanding our access to acquisitions and evaluating oil and natural gas assets expands our opportunities and differentiates us from many of our competitors. We expect to have the opportunity to work jointly with Memorial Resource to pursue acquisitions of oil and natural gas properties that we would not otherwise be able to pursue on our own or that may not otherwise be attractive acquisition candidates for either of us individually.

 

  Ÿ  

Our relationship with Memorial Resource, which provides us with extensive technical expertise in and familiarity with developing and operating oil and natural gas assets within our core focus areas. Through our omnibus agreement with Memorial Resource, we have the operational support of petroleum professionals, many of whom have significant engineering and geoscience expertise in South Texas and/or East Texas/North Louisiana. In addition, Memorial Resource intends to employ substantially all of the employees currently operating the Beta properties, and to provide those employees to us, following our acquisition of the Beta properties. After completion of the Beta acquisition, Memorial Resource expects to have a team of over 300 employees, including over 60 engineers, geologists and land professionals as well as other experienced exploration, development and production professionals. We believe that this technical expertise and depth differentiates us from, and provides us with a competitive advantage over, many of our competitors. We intend to continue to utilize these resources in maximizing our production and ultimate reserve recovery, which could add substantial value to our assets.

 

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  Ÿ  

Our diverse distribution of reserve value, with 1,667 gross (729 net) producing wells pro forma as of September 30, 2012, none of which contains estimated proved reserves in excess of 2% of our total combined pro forma estimated proved reserves as of September 30, 2012. The value of our total estimated proved reserves, as approximated by the standardized measure, is spread across a wide subset of our producing wells. Our top 10 wells by value represent 17% of our total pro forma standardized measure of $820.1 at September 30, 2012.

 

  Ÿ  

Our substantial inventory of proved operated infill drilling, recompletion and development opportunities. We have a substantial inventory of low risk, proved undeveloped locations. At September 30, 2012, our properties included approximately 233.6 Bcfe of estimated proved undeveloped reserves, and had 210 proved identified low-risk proved drilling locations and 363 proved recompletion and development opportunities. In 2013, our capital spending program is expected to be approximately $60 to $70 million (including maintenance capital expenditures). At September 30, 2012, we or Memorial Resource operated 95% of the properties in which we have an interest.

 

  Ÿ  

Our competitive cost of capital and financial flexibility. Unlike our corporate competitors, we do not expect to be subject to federal income taxation at the entity level. We believe that this attribute should provide us with a lower cost of capital compared to many of our competitors, thereby enhancing our ability to compete for future acquisitions, both individually and jointly with Memorial Resource. We also expect that our ability to issue additional common units and other partnership interests in connection with acquisitions will enhance our financial flexibility. Further, we intend to utilize a modest amount of debt to provide flexibility in our capital structure.

 

  Ÿ  

Our management team’s extensive experience in the acquisition, development and successful integration of oil and natural gas assets. The members of our management team and Memorial Resource collectively have an average of 23 years of experience in the oil and natural gas industry. John A. Weinzierl, the President, Chief Executive Officer and Chairman of our general partner, has over 21 years of oil and natural gas industry experience, a strong commercial and technical background and extensive experience acquiring and managing oil and natural gas properties. Andrew J. Cozby, the Vice President and Chief Financial Officer of our general partner, and Larry R. Forney, the Vice President, Operations and Asset Management of our general partner, collectively have over 47 years of oil and natural gas experience, including significant experience acquiring and successfully integrating oil and natural gas assets. Messrs. Cozby and Forney have developed strong business relationships with key industry participants throughout our core focus areas. We believe our management team’s collective knowledge of the industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions will provide us with opportunities to grow through strategic and accretive acquisitions that complement or expand our existing operations.

 

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Our Principal Business Relationships

Our Relationship with Memorial Resource

Memorial Resource is a Delaware limited liability company formed by the Funds to own, acquire, exploit and develop oil and natural gas properties and to own our general partner. As part of our formation transactions in connection with our initial public offering, the Funds contributed to Memorial Resource their respective ownership of five separate portfolio companies (including those comprising 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 contributed our properties to us. Memorial Resource is engaged in its business with the objective of growing its reserves, production and cash flows, as well as owning our general partner and a significant limited partner interest in us.

Memorial Resource is our largest unitholder, holding 7,061,294 common units (approximately 25.7% of all outstanding immediately following this offering) and 5,360,912 subordinated units (100% of all outstanding), and owns all of the voting interests in our general partner and 50% of the economic interest in our incentive distribution rights. Memorial Resource has pledged our common and subordinated units that it owns, as well as its ownership interest in our general partner, as security under its senior secured revolving credit facility in addition to certain other assets of Memorial Resource. Our general partner has entered into an omnibus agreement with Memorial Resource and the Partnership in which Memorial Resource has agreed to provide the administrative, management and operational services that we believe are necessary to allow our general partner to manage, operate and grow our business.

As of June 30, 2012, excluding the properties sold to us during 2012, Memorial Resource had (i) total estimated proved reserves of over 1,235 Bcfe, primarily located in East Texas, North Louisiana and the Rockies and (ii) interests in over 579,570 gross (335,323 net) acres of 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 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/North Louisiana 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.

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. For example, during 2012 we acquired two sets of properties from Memorial Resource, and we also completed an acquisition of properties via a joint bid with Memorial Resource. However, Memorial Resource regularly evaluates 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. Although we believe Memorial Resource is incentivized to offer properties to us for purchase, none of Memorial Resource, the Funds or any of their respective affiliates has any obligation to sell or offer properties to us. Please read “Conflicts of Interest and Fiduciary Duties.”

 

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Our Relationship with Natural Gas Partners and the Funds

Founded in 1988, NGP is a family of private equity investment funds, with cumulative committed capital of approximately $10.5 billion since inception, organized to make investments in the natural resources sector. NGP is part of the investment platform of NGP Energy Capital Management, a premier investment franchise in the natural resources industry, which together with its affiliates has managed approximately $13 billion in cumulative committed capital since inception. 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 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 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. For example, we will acquire the Beta properties from a seller that is primarily owned by two of the Funds.

Our Areas of Operations

The following discussion reflects activity on a pro forma basis as of, and for the nine months ended, September 30, 2012 and as of September 30, 2012, giving effect to the Beta acquisition.

South Texas

Approximately 30% of our pro forma estimated proved reserves as of September 30, 2012 and approximately 34% of our average daily pro forma net production for the nine months ended September 30, 2012 were located in the South Texas region. Our South Texas properties include wells and properties in numerous natural gas weighted fields located in McMullen, Live Oak, Duval, Jim Hogg, Webb and Zapata Counties, Texas, including the NE Thompsonville, Laredo and East Seven Sisters fields. Our South Texas properties contained 176.1 Bcfe of estimated pro forma net proved reserves as of September 30, 2012 based on our reserve reports. Those properties collectively generated average pro forma net production of 27.5 MMcfe/d for the nine months ended September 30, 2012.

East Texas/North Louisiana

Approximately 56% of our pro forma estimated proved reserves as of September 30, 2012 and approximately 54% of our average daily net production for the nine months ended September 30, 2012 were located in the East Texas/North Louisiana region. Our East Texas/Louisiana properties

 

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include wells and properties located in Navarro, Anderson, Wood, Upshur, Gregg, Harrison, Rusk, Panola, Leon, Polk, Smith, Tyler and Shelby Counties, Texas and De Soto, Lincoln and Union Parishes, Louisiana. Those properties collectively contained 337.2 Bcfe of pro forma estimated net proved reserves as of September 30, 2012 based on our reserve reports and generated average pro forma net production of 42.9 MMcfe/d for the nine months ended September 30, 2012. Our East Texas/North Louisiana properties include properties in the Joaquin and Carthage fields, adjacent natural gas weighted fields located in Panola and Shelby Counties, the Cotton Valley and Travis Peak fields also located in Panola and Shelby Counties, the Willow Springs field located in Gregg County, the South Henderson field located in Rusk County, and the Terryville field located in Lincoln Parish.

California

Please read “Beta Acquisition” for a description of our properties offshore Southern California.

Our Oil and Natural Gas Data

Our Reserves

Internal Controls. Ninety-seven percent of our proved reserves are estimated at the well or unit level and compiled for reporting purposes by NSAI, our independent reserve engineers. Memorial Resource maintains internal evaluations of our reserves in a secure reserve engineering database. NSAI interacts with Memorial Resource’s internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting and marketing employees to obtain the necessary data for the reserves estimation process. Reserves are reviewed and approved internally by our senior management on a semi-annual basis. Our reserve estimates are evaluated by NSAI at least annually.

Our internal professional staff works closely with NSAI to ensure the integrity, accuracy and timeliness of data that is furnished to it for its reserve estimation process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, we provide NSAI other pertinent data, such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make all requested information, as well as our pertinent personnel, available to the external engineers as part of their evaluation of our reserves.

Qualifications of Responsible Technical Persons

Internal Engineers. Larry R. Forney and John D. Williams are the technical persons at Memorial Resource primarily responsible for liaison with and oversight of our third-party reserve engineers, NSAI, which prepared the reserve report for our properties. Mr. Forney has served as our general partner’s Vice President of Operations and Asset Management since August 2011. From August 2008 to August 2011, Mr. Forney served as President of Mossback Management LLC, a private entity providing contract operating and engineering consulting services, including managing all operations and related business functions for Hungarian Horizon Energy, Ltd and Central European Drilling, Ltd in Budapest, Hungary from July 2010 to August 2011. From July 2004 to July 2008, Mr. Forney served as Vice President of Operations for Greystone Oil & Gas LLP and Managing Director of Greystone Drilling LP. Mr. Forney served as Vice President of Operations for Greystone Petroleum LLC from 2002 until 2004. Mr. Forney was Vice President and Treasurer of Goldrus Producing Company from 1997 to 2002. From 1990 to 1997, Mr. Forney held various positions for the Kelley Oil companies, which culminated in his serving concurrently as Vice

 

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President of Operations for Kelley Oil Corporation and Vice President of Concorde Gas Marketing. Prior to 1990, Mr. Forney held various drilling, production and facility construction positions with Pacific Enterprises Oil Corporation and Kerr-McGee Corporation. Mr. Forney is a graduate of the University of Texas at Austin with a B.S. in petroleum engineering and a registered professional engineer in Texas.

Mr. Williams has been practicing petroleum engineering at Memorial Resource since March 2012. Mr. Williams is a Registered Professional Engineer in the State of Texas with over 17 years experience in the estimation and evaluation of reserves. From April 2005 to March 2012, he held various positions at Southwestern Energy Company, most recently as Reservoir Engineering Manager. From August 1998 to April 2005, he served in various capacities at Ryder Scott Company, which culminated in his serving as Vice President. Mr. Williams is a graduate of the University of Texas at Austin with a Bachelor of Science Degree in Petroleum Engineering and with a Master of Science Degree in Petroleum Engineering.

Netherland, Sewell & Associates, Inc. NSAI is an independent oil and natural gas consulting firm. No director, officer, or key employee of NSAI has any financial ownership in us, Memorial Resource, the Funds, or any of their respective affiliates. NSAI’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported. NSAI has not performed other work for us, Memorial Resource, the Funds, or any of their respective affiliates that would affect its objectivity.

The estimates of our proved reserves at September 30, 2012 presented in the NSAI report, and the engineering audit presented in the NSAI report relating to the estimates of our proved reserves at September 30, 2012 made by our internal reservoir engineers and the estimates of proved reserves attributable to the Beta properties at September 30, 2012 presented in the NSAI report were overseen by Mr. Philip S. (Scott) Frost; Mr. Justin S. Hamilton; Mr. David E. Nice; Mr. Richard B. Talley, Jr.; Mr. Joseph J. Spellman; and Mr. J. Carter Henson, Jr.

Scott Frost has been practicing consulting petroleum engineering at NSAI since 1984. Mr. Frost is a Licensed Professional Engineer in the State of Texas (License No. 88738) and has over 30 years of practical experience in petroleum engineering, with over 30 years experience in the estimation and evaluation of reserves. He graduated from Vanderbilt University in 1979 with a Bachelor of Engineering in Mechanical Engineering and from Tulane University in 1984 with a Master of Business Administration Degree.

Justin Hamilton has been practicing consulting petroleum engineering at NSAI since 2004. Mr. Hamilton is a Licensed Professional Engineer in the State of Texas (License No. 104999) and has over 10 years of practical experience in petroleum engineering, with over 10 years experience in the estimation and evaluation of reserves. He graduated from Brigham Young University in 2000 with a Bachelor of Science Degree in Mechanical Engineering and from the University of Texas in 2007 with a Master of Business Administration Degree.

David Nice has been practicing consulting petroleum geology at NSAI since 1998. Mr. Nice is a Licensed Professional Geoscientist in the State of Texas (License No. 346) and has over 26 years of practical experience in petroleum geosciences, with over 13 years experience in the estimation and evaluation of reserves. He graduated from University of Wyoming in 1982 with a Bachelor of Science Degree in Geology and in 1985 with a Master of Science Degree in Geology.

Richard Talley has been practicing consulting petroleum engineering at NSAI since 2004. Mr. Talley is a Licensed Professional Engineer in the State of Texas (License No. 102425) and in the State of Louisiana (License No. 36998) and has over 13 years of practical experience in petroleum engineering, with over 7 years experience in the estimation and evaluation of reserves. He graduated from University of Oklahoma in 1998 with a Bachelor of Science Degree in Mechanical Engineering and from Tulane University in 2001 with a Master of Business Administration Degree.

 

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Joseph Spellman has been practicing consulting petroleum engineering at NSAI since 1989. Mr. Spellman is a Registered Professional Engineer in the State of Texas (License No. 73709) and has 33 years of practical experience in petroleum engineering, with over 30 years experience in the estimation and evaluation of reserves. He graduated from University of Wisconsin-Platteville in 1980 with a Bachelor of Science Degree in Civil Engineering.

J. Carter Henson, Jr. has been practicing consulting petroleum engineering at NSAI since 1989. Mr. Henson is a Licensed Professional Engineer in the State of Texas (License No. 73964) and has over 30 years of practical experience in petroleum engineering, with over 23 years of experience in the estimation and evaluation of reserves. He graduated from Rice University in 1981 with a Bachelor of Science Degree in Mechanical Engineering.

All technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; all are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Estimated Proved Reserves

The following table presents the estimated net proved oil and natural gas reserves attributable to our properties and the Beta properties and the standardized measure amounts associated with the estimated proved reserves attributable to our properties and the Beta properties as of September 30, 2012, based on our reserve report audited by NSAI, our independent reserve engineers, and with respect to the Beta properties, on the reserve report prepared by NSAI. The standardized measure amounts shown in the table are not intended to represent the current market value of estimated oil and natural gas reserves.

 

     As of September 30, 2012  
     Memorial Production
Partners LP
Historical
    Beta Properties
Historical
    Memorial Production
Partners LP

Pro Forma Combined
 

Estimated Proved Reserves

      

Oil (MMBbls)

     4.7        14.3        19.0   

NGLs (MMBbls)

     16.7               16.7   

Natural gas (Bcf)

     384.8               384.8   
  

 

 

   

 

 

   

 

 

 

Total (Bcfe) (1)

     513.3        86.0        599.3   

Proved developed (Bcfe)

     305.9        59.8        365.7   

Proved undeveloped (Bcfe)

     207.4        26.2        233.6   

Proved developed reserves as a percentage of total proved reserves

     60     70     61

Standardized measure (in millions) (2)

   $ 427.3      $ 392.8      $ 820.1   

Oil and Natural Gas Prices (3)

      

Oil—NYMEX—WTI per Bbl

   $ 93.78      $ 105.44      $ 99.88   

Natural gas—NYMEX—Henry Hub per MMBtu

   $ 2.82      $      $ 2.82   

 

(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.

 

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(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 depletion, depreciation 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 or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions. For a description of our commodity derivative contracts, please read “—Operations—Derivative Activities” as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Commodity Derivative Contracts” included in our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2012 and our Current Report on Form 8-K filed with the SEC on November 20, 2012, each of which is incorporated by reference herein.
(3) Our estimated net proved reserves and related standardized measure were determined using 12-month average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month in effect as of the date of the estimate, 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. The unweighted average of the first-day-of-the-month prices for each of the twelve months ending September 30, 2012 were $91.48/Bbl for oil and $2.83/MMBtu for natural gas.

The data in the table above represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. For a discussion of risks associated with internal reserve estimates, please read “Risk Factors—Risks Related to Our Business—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.”

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure amounts shown above should not be construed as the current market value of our estimated oil and natural gas reserves. The 10% discount factor used to calculate standardized measure, which is required by the FASB, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Development of Proved Undeveloped Reserves

None of our pro forma proved undeveloped reserves as of September 30, 2012 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as proved undeveloped. Historically, Memorial Resource’s drilling and development programs were substantially funded from its cash flow from operations. Our expectation is to continue to fund our drilling and development programs, with respect to maintenance capital expenditures, primarily from our cash flow from operations, and to fund growth capital expenditures with external capital. Based on our current expectations of our cash flows and available external capital (including our revolving credit facility), as well as our drilling and development programs, which includes drilling of proved undeveloped locations, we believe that we can fund the drilling of our current inventory of proved undeveloped locations and our expansions in the next five years from our cash flow from operations and, if needed, our revolving credit facility. For a more detailed discussion of our liquidity position, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” included in our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2012, which is incorporated by reference herein.

 

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Production, Revenue and Price History

The following table sets forth information regarding combined net production of oil and natural gas and certain price and cost information (i) of us on a historical basis, (ii) of the Beta properties on a historical basis and (iii) of us on a pro forma combined basis for each of the periods presented:

 

    Year Ended December 31,
2011
    Nine Months Ended September 30,
2012
 
    Memorial
Production
Partners LP
Historical (2)
    Beta
Properties
Historical
    Memorial
Production
Partners  LP

Pro Forma
Combined (3)
    Memorial
Production
Partners LP
Historical (2)
    Beta
Properties
Historical
    Memorial
Production
Partners  LP

Pro Forma
Combined (3)
 

Production and operating data:

           

Net production volumes:

           

Oil (MBbls)

    97        591        858        105        431        619   

NGLs (MBbls)

    182               299        236               254   

Natural gas (MMcf)

    15,936               22,894        13,242               16,631   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total (MMcfe)

    17,608        3,547        29,836        15,288        2,587        21,868   

Average net production (MMcfe/d)

    48.2        9.7        81.7        55.8        9.4        79.8   

Average sales price: (1)

           

Oil (per Bbl)

  $ 91.43      $ 102.74      $ 100.00      $ 95.77      $ 104.45      $ 102.52   

NGLs (per Bbl)

  $ 51.70      $      $ 50.46      $ 36.94      $      $ 37.59   

Natural gas (per Mcf)

  $ 4.13      $      $ 4.07      $ 2.72      $      $ 2.87   

Average price per Mcfe

  $ 4.77      $ 17.12      $ 6.50      $ 3.58      $ 17.41      $ 5.52   

Average unit costs per Mcfe:

           

Lease operating expenses

  $ 1.39      $ 5.64      $ 1.67      $ 1.25      $ 5.98      $ 1.69   

Production taxes

  $ 0.27      $      $ 0.29      $ 0.34      $      $ 0.30   

General and administrative expenses

  $ 0.59      $ 1.18      $ 0.48      $ 0.45      $ 1.22      $ 0.46   

Depletion, depreciation and amortization

  $ 1.71      $ 1.46      $ 1.62      $ 1.54      $ 1.57      $ 1.56   

 

(1) Prices do not include the effects of derivative cash settlements.
(2) Includes data with respect to the properties acquired from Memorial Resource in April and May 2012, which acquisitions were accounted for as transactions between entities under common control, similar to a pooling of interests.
(3) Includes data with respect to the Beta properties, as wells as the properties we acquired from third parties in 2011 and 2012.

Productive Wells

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells. The following table sets forth pro forma information relating to the productive wells in which we owned a working interest as of September 30, 2012.

 

     Oil      Natural Gas  
     Gross      Net      Gross      Net  

Operated (1)

     60         31         1,124         664   

Non-operated

     0         0         483         34   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     60         31         1,607         698   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Includes wells operated by Memorial Resource on our behalf.

 

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Developed Acreage

Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. As of September 30, 2012, all of our leasehold acreage was held by production. The following table sets forth pro forma information as of September 30, 2012 relating to our leasehold acreage.

 

     Developed Acreage (1)  
     Gross (2)      Net (3)  

South Texas

     82,400         72,745   

East Texas/North Louisiana

     62,968         35,656   

California

     4,050         2,096   
  

 

 

    

 

 

 

Total

     149,418         110,497   

 

(1) Developed acreage, all of which is held by production, includes acreage subject to infill drilling.
(2) A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.
(3) A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Undeveloped Acreage

The following table sets forth pro forma information as of September 30, 2012 relating to our undeveloped leasehold acreage.

 

     Undeveloped Acreage  
     Gross (1)      Net (2)  

South Texas

               

East Texas/North Louisiana

     483         168   

California

               
  

 

 

    

 

 

 

Total

     483         168   
  

 

 

    

 

 

 

 

(1) A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.
(2) A net acre is deemed to exist when the sum of our fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

 

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Drilling Activities

Our drilling activities consist entirely of development wells. The following table sets forth pro forma information with respect to wells drilled and completed by us during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.

 

     Year Ended
December 31, 2011
     Nine-Months Ended
September 30, 2012
 
     Gross      Net      Gross      Net  

Development wells:

           

Productive

     4.0         3.1         4.0         1.1   

Dry

                               

Exploratory wells:

           

Productive

                               

Dry

                               

Total wells:

           

Productive

     4.0         3.1         4.0         1.1   

Dry

                               
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     4.0         3.1         4.0         1.1   
  

 

 

    

 

 

    

 

 

    

 

 

 

Delivery Commitments

We have no commitments to deliver a fixed and determinable quantity of our oil or natural gas production in the near future under our existing contracts.

Operations

General

As of September 30, 2012, we or Memorial Resource operated 95% of the wells and properties containing our proved reserves on a pro forma basis on our behalf and also is the operator of substantially all of the other wells and properties containing our proved reserves. We design and manage the development, recompletion and/or workover operations, and supervise other operation and maintenance activities, for all of the wells we operate. We do not own the drilling rigs or other oil field services equipment used for drilling or maintaining wells on our properties. Independent contractors provide all the equipment and personnel associated with these activities. Pursuant to our omnibus agreement, Memorial Resource provides management, administrative and operating services to our general partner and us to manage and operate our business and assets. Please read “Certain Relationships and Related Party Transactions—Related Party Agreements—Omnibus Agreement” for more information about the omnibus agreement.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any well drilled on the lease premises. The lessor royalties and other leasehold burdens on our properties

 

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range from 0% to 59%, or 17% on average, resulting in a net revenue interest to us ranging from 41% to 100%. As of September 30, 2012, most of our leases are held by production and do not require lease rental payments.

Derivative Activities

We enter into commodity derivative contracts with unaffiliated third parties to achieve more predictable cash flows and to reduce our exposure to fluctuations in oil and natural gas prices. Our outstanding commodity derivative contracts currently consist of floating-for-fixed swaps, collars, put options, and basis swaps.

Swaps. In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published third-party index, if the index price is lower than the fixed price. If the index price is higher, we pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our swaps are settled in cash on a monthly basis.

Basis Swaps. These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point. Our basis protection swaps typically have negative differentials to NYMEX. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and we pay the counterparty if the price differential is less than the stated terms of the contract.

Put Options. In a typical put option arrangement, we receive the excess, if any, of the contract floor price over the reference price, based on NYMEX quoted prices. Our current put options are exercised and settled in cash on a monthly basis only when the floor price exceeds the reference price, otherwise they expire unsettled.

Collars. In a typical collar arrangement, we receive the excess, if any, of the contract floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the contract ceiling price. Our current collars are exercised in cash on a monthly basis only when the reference price is outside of floor and ceiling prices (the collar), otherwise they expire.

 

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The following table summarizes our derivative contracts as of December 5, 2012, giving effect to the Beta acquisition, and the average prices at which the production is hedged:

 

    Remaining
2012
    Year Ending December 31,  
      2013     2014     2015     2016     2017  

Natural Gas Derivative Contracts:

           

Swap contracts:

           

Volume (MMBtu/d)

    22,229        41,019        44,125        39,653        36,501        32,550   

Weighted-average swap price

  $ 4.50      $ 4.42      $ 4.41      $ 4.34      $ 4.53      $ 4.29   

Collar contracts:

           

Volume (MMBtu/d)

    18,913        6,674                               

Weighted-average ceiling price

  $ 5.87      $ 5.80                               

Weighted-average floor price

  $ 4.83      $ 5.07                               

Put options:

           

Volume (MMBtu/d)

    2,283                                      

Weighted-average put price

  $ 4.80                                      

Total Natural Gas Derivative Contracts:

           

Total natural gas volumes hedged (MMBtu/d)

    43,425        47,693        44,125        39,653        36,501        32,550   

Total weighted-average fixed/floor price

  $ 4.66      $ 4.51      $ 4.41      $ 4.34      $ 4.53      $ 4.29   

Crude Oil Derivative Contracts:

           

Swap contracts:

           

Volume (Bbl/d)

    318        317        661        396        361        329   

Weighted-average swap price

  $ 93.69      $ 94.06      $ 94.06      $ 90.29      $ 90.39      $ 88.30   

Collar contracts:

           

Volume (Bbl/d)

    1,451        1,471        1,287        1,479        1,443        1,381   

Weighted-average ceiling price

  $ 104.45      $ 115.91      $ 108.91      $ 104.34      $ 103.40      $ 99.00   

Weighted-average floor price

  $ 78.43      $ 94.17      $ 94.97      $ 90.00      $ 85.00      $ 85.00   

Put options:

           

Volume (Bbl/d)

                                         

Weighted-average put price

                                         

Total Crude Oil Derivative Contracts:

           

Total crude oil volumes hedged (Bbl/d)

    1,769        1,788        1,948        1,875        1,804        1,710   

Total weighted-average fixed/floor price

  $ 81.17      $ 94.15      $ 94.67      $ 90.06      $ 86.08      $ 85.63   

Natural Gas Liquids Derivative Contracts:

           

Swap contracts:

           

Volume (Bbl/d)

    689        816        266                        

Weighted-average swap price

  $ 43.77      $ 48.72      $ 58.92                        

Collar contracts:

           

Volume (Bbl/d)

    124                                      

Weighted-average ceiling price

  $ 93.57                                      

Weighted-average floor price

  $ 75.16                                      

Put options:

           

Volume (Bbl/d)

                                         

Weighted-average put price

                                         

Total Natural Gas Liquids Derivative Contracts:

           

Total NGL volumes hedged (Bbl/d)

    813        816        266                        

Total weighted-average fixed/floor price

  $ 48.55      $ 48.72      $ 58.92                        

 

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PRICE RANGE OF COMMON UNITS AND DISTRIBUTION

Our common units are listed and traded on the NASDAQ Global Market under the symbol “MEMP.” Our common units began trading on December 9, 2011 at an initial public offering price of $19.00 per common unit. As reported by the NASDAQ Global Market, the following table shows the low and high sales prices per common unit for the periods indicated. Distributions are shown in the quarter for which they were paid.

 

     High      Low      Cash
Distribution
per Unit (1)(2)
 

2012

        

Fourth Quarter (through December 4, 2012)

   $ 20.75       $ 17.10       $ (2) 

Third Quarter

     19.14         16.40         0.4950   

Second Quarter

     18.79         15.71         0.4800   

First Quarter

     19.05         16.59         0.4800   

2011

        

Fourth Quarter (1)

   $ 19.09       $ 17.51       $ 0.0929 (3) 

 

(1) From December 9, 2011, the day our common units began trading on the NASDAQ Global Market, through December 31, 2011.
(2) On November 19, 2012, the board of directors of our general partner approved, subject to the completion of the Beta acquisition, an increase in our cash distribution rate attributable to the fourth quarter of 2012 to $0.5075 per unit.
(3) Reflects the pro rata portion of the $0.4750 quarterly distribution per unit paid, representing the period from the December 14, 2011 closing of our initial public offering through December 31, 2011. An identical cash distribution was paid to all unitholders of record at the close of business on February 6, 2012, except for the holders of 177,370 restricted common units that were granted to our general partner’s executive officers and independent director on January 9, 2012.

The last reported sale price of our common units on the NASDAQ Global Market on December 4, 2012 was $18.25. As of December 4, 2012, there were approximately 41 holders of record of our common units.

 

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.

Definition of Available Cash

Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:

 

  Ÿ  

less, the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to:

 

  Ÿ  

provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for capital expenditures, working capital and operating expenses;

 

  Ÿ  

comply with applicable law, any of our debt instruments or other agreements; or

 

  Ÿ  

provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for future distributions on our common and subordinated units unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for such quarter);

 

  Ÿ  

plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from borrowing (including working capital borrowings) made after the end of the quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from borrowing (including working capital borrowings) made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders.

Working capital borrowings are borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months from sources other than additional working capital borrowings.

Intent to Distribute the Minimum Quarterly Distribution

We intend to distribute to the holders of common units, subordinated units and general partner units on a quarterly basis at least the minimum quarterly distribution of $0.4750 per unit, or $1.90 per unit on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and payment of fees and expenses, including payments (or

 

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reserving for payment) of fees and expenses to our general partner and its affiliates. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

General Partner Interest and Incentive Distribution Rights

Currently, our general partner is entitled to 0.1% of all quarterly distributions that we make prior to our liquidation. Our general partner’s 0.1% interest in us is currently represented by 22,330 general partner units for allocation and distribution purposes. Immediately following this offering, our general partner’s 0.1% interest in us will be represented by 32,840 general partner units (or 34,417 general partner units if the underwriters exercise their option to purchase additional common units in full). Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its current general partner interest. Our general partner’s 0.1% interest in our distributions will be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon the conversion of outstanding subordinated units) and our general partner does not contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its general partner interest.

Our general partner also holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 25.0%, of the cash we distribute from operating surplus (as defined below) in excess of $0.54625 per unit per quarter. The maximum distribution of 25.0% includes distributions paid to our general partner on its 0.1% general partner interest and assumes that our general partner maintains its general partner interest at 0.1%. The maximum distribution of 25.0% does not include any distributions that our general partner may receive on common units or subordinated units that it owns. The Funds hold non-voting member interests in our general partner that entitle them collectively to 50.0% of all cash distributions received by our general partner in respect of the incentive distribution rights and any common units issued to our general partner in connection with a reset of the incentive distribution rights.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Operating Surplus

Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus. Operating surplus for any period consists of:

 

  Ÿ  

$30.5 million (as described below); plus

 

  Ÿ  

all of our cash receipts since the closing of our initial public offering, excluding cash from interim capital transactions, which include the following:

 

  Ÿ  

borrowings (including sales of debt securities) that are not working capital borrowings;

 

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  Ÿ  

sales of equity interests; and

 

  Ÿ  

sales or other dispositions of assets outside the ordinary course of business;

provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge; plus

 

  Ÿ  

working capital borrowings made after the end of the period but on or before the date of determination of operating surplus for the period; plus

 

  Ÿ  

cash distributions paid (including incremental incentive distributions) on equity issued to finance all or a portion of the construction, replacement, acquisition, development or improvement of a capital improvement or replacement of a capital asset (such as reserves or equipment) in respect of the period beginning on the date that we enter into a binding obligation to commence the construction, replacement, acquisition, development or improvement of a capital improvement, construction, replacement, acquisition, development or improvement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset begins producing in paying quantities or is placed into service, as applicable, and the date that it is abandoned or disposed of; plus

 

  Ÿ  

cash distributions paid (including incremental incentive distributions) on equity issued to pay the construction period interest on debt incurred (including periodic net payments under related interest rate swap arrangements), or to pay construction period distributions on equity issued, to finance the capital improvements or capital assets referred to above; less

 

  Ÿ  

all of our operating expenditures (as described below) since the closing of our initial public offering; less

 

  Ÿ  

the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

 

  Ÿ  

all working capital borrowings not repaid within twelve months after having been incurred, or repaid within such twelve month period with the proceeds of additional working capital borrowings; less

 

  Ÿ  

any cash loss realized on disposition of an investment capital expenditure.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by our operations. For example, it includes a basket of $30.5 million that enables us, if we choose, to distribute as operating surplus $30.5 million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including (as described above) certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus

 

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reduce operating surplus when repayments are made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deemed repayment.

We define operating expenditures in our partnership agreement, and it generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement for expenses of our general partner and its affiliates, payments made in the ordinary course of business under interest rate and commodity hedge contracts, (provided that (i) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or commodity hedge contract and (ii) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), officer compensation, repayment of working capital borrowings, debt service payments (except as otherwise provided in our partnership agreement) and estimated maintenance capital expenditures (as discussed in further detail below), provided that operating expenditures will not include:

 

  Ÿ  

repayment of working capital borrowings previously deducted from operating surplus pursuant to the provision described in the penultimate bullet point of the description of operating surplus above when such repayment actually occurs;

 

  Ÿ  

payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;

 

  Ÿ  

growth capital expenditures;

 

  Ÿ  

actual maintenance capital expenditures (as discussed in further detail below);

 

  Ÿ  

investment capital expenditures;

 

  Ÿ  

payment of transaction expenses relating to interim capital transactions;

 

  Ÿ  

distributions to our partners; or

 

  Ÿ  

repurchases of equity interests except to fund obligations under employee benefit plans.

Capital Surplus

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, capital surplus would generally be generated by:

 

  Ÿ  

borrowings (including sales of debt securities) other than working capital borrowings;

 

  Ÿ  

sales of our equity interests; and

 

  Ÿ  

sales or other dispositions of assets outside the ordinary course of business.

 

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Characterization of Cash Distributions

Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of our initial public offering equals the operating surplus from the closing of of our initial public offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes $30.5 million, which does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it is a provision that enables us, if we choose, to distribute as operating surplus up to this amount of cash we receive from non-operating sources such as asset sales, issuances of securities, and borrowings, that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Estimated maintenance capital expenditures reduce operating surplus, but growth capital expenditures, actual maintenance capital expenditures and investment capital expenditures do not. Maintenance capital expenditures are those capital expenditures required to maintain our asset base over the long term. We expect that a primary component of maintenance capital expenditures will be capital expenditures associated with the replacement of equipment and 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 and natural gas property. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of any replacement asset that is paid in respect of the period from such financing until the earlier to occur of the date that any such construction, replacement, acquisition or improvement of a capital improvement or construction replacement, acquisition or improvement of a capital asset begins producing in paying quantities or is placed into service, as applicable, and the date that it is abandoned or disposed of. Plugging and abandonment cost will also constitute maintenance capital expenditures. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus and adjusted operating surplus if we subtracted actual maintenance capital expenditures from operating surplus. To address this issue, our partnership agreement requires that an estimate of the average quarterly maintenance capital expenditures (including estimated plugging and abandonment costs) necessary to maintain our asset base over the long term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by our general partner’s board of directors at least once a year, provided that any change is approved by the conflicts committee of our general partner’s board of directors. The estimate is made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only.

 

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The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

 

  Ÿ  

it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units for the quarter;

 

  Ÿ  

it will increase our ability to distribute as operating surplus cash we receive from non-operating sources;

 

  Ÿ  

in quarters where estimated maintenance capital expenditures exceed actual maintenance capital expenditures, it will be more difficult for us to raise our distribution above the minimum quarterly distribution, because the amount of estimated maintenance capital expenditures will reduce the amount of cash available for distribution to our unitholders, even in quarters where there are no corresponding actual capital expenditures; conversely, the use of estimated maintenance capital expenditures in calculating operating surplus will have the opposite effect for quarters in which actual maintenance capital expenditures exceed our estimated maintenance capital expenditures; and

 

  Ÿ  

it will reduce the likelihood that a large maintenance capital expenditure during a particular quarter will prevent our general partner’s affiliates from being able to convert some or all of their subordinated units to common units since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.

Growth capital expenditures are those capital expenditures that we expect will increase our asset base over the long term. Examples of growth capital expenditures include the acquisition of reserves or equipment, the acquisition of new leasehold interest, or the development, exploitation and production of an existing leasehold interest, to the extent such expenditures are incurred to increase our asset base over the long term. Growth capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of such capital improvement during the period from such financing until the earlier to occur of the date any such capital improvement begins producing in paying quantities or is placed into service, as applicable, or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered growth capital expenditures.

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor growth capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of our undeveloped properties in excess of the maintenance of our asset base, but which are not expected to expand our asset base for more than the short term.

As described above, neither investment capital expenditures nor growth capital expenditures will be included in operating expenditures, and thus will not reduce operating surplus. Because growth capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of the construction, replacement or improvement of a capital asset (such as equipment or reserves) during the period from such financing until the earlier to occur of the date any such capital asset begins producing in paying quantities or is placed into service, as

 

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applicable, and the date that it is abandoned or disposed of, such interest payments also do not reduce operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

Capital expenditures that are made in part for maintenance capital purposes and in part for investment capital or growth capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or growth capital expenditure by our general partner’s board of directors, based upon its good faith determination, subject to approval by the conflicts committee of our general partner’s board of directors.

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we describe below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4750 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.

Expiration of the Subordination Period

Except as described below under “—Early Conversion of Subordinated Units,” the subordination period will extend until the first business day after the distribution to unitholders in respect of any quarter ending on or after December 31, 2014 that each of the following tests are met:

 

  Ÿ  

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaled or exceeded, in the aggregate, the sum of the minimum quarterly distributions payable with respect to a period of twelve consecutive quarters immediately preceding such date;

 

  Ÿ  

the “adjusted operating surplus” (as defined below) generated during the period of twelve consecutive quarters immediately preceding that date equaled or exceeded, in the aggregate, the sum of the minimum quarterly distributions on all of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units that were outstanding during these periods payable with respect to such period on a fully diluted weighted average basis; and

 

  Ÿ  

there are no arrearages in payment of the minimum quarterly distribution on the common units.

 

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Early Conversion of Subordinated Units

The subordination period will automatically terminate, and all of the subordinated units will convert into an equal number of common units, on the first business day after the distribution to unitholders in respect of any quarter ending on or after December 31, 2012, if the following tests are met:

 

  Ÿ  

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaled or exceeded $0.59375 (125% of the minimum quarterly distribution) per quarter for the four quarter period immediately preceding that date;

 

  Ÿ  

the “adjusted operating surplus” generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of a distribution of $2.3750 (125% of the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units, in each case that were outstanding during such four quarter period on a fully diluted weighted average basis, and the corresponding distributions on the incentive distribution rights; and

 

  Ÿ  

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Effect of the Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. Common units will then no longer be entitled to arrearages.

Effect of the Expiration of the Subordination Period Following Removal of our General Partner

If the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:

 

  Ÿ  

the subordination period will end and each subordinated unit will immediately convert into one common unit;

 

  Ÿ  

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

 

  Ÿ  

our general partner will have the right to convert its general partner units into common units or to receive cash in exchange for such general partner units at the equivalent common unit fair market value.

Adjusted Operating Surplus

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus for any period consists of:

 

  Ÿ  

operating surplus generated with respect to that period (excluding the amount described in the first bullet point under “—Operating Surplus and Capital Surplus—Operating Surplus”); less

 

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  Ÿ  

any net increase in working capital borrowings with respect to that period; less

 

  Ÿ  

any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

 

  Ÿ  

any net decrease in working capital borrowings with respect to that period; plus

 

  Ÿ  

any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium; plus

 

  Ÿ  

any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to such period to the extent such decrease results in a reduction of adjusted operating surplus in subsequent periods pursuant to the third bullet point above.

Distributions of Available Cash from Operating Surplus During the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

 

  Ÿ  

first, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

 

  Ÿ  

second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

 

  Ÿ  

third, 99.9% to the subordinated unitholders, pro rata, and 0.1% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

 

  Ÿ  

thereafter, in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its current general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus After the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

 

  Ÿ  

first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

 

  Ÿ  

thereafter, in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its current general partner interest and that we do not issue additional classes of equity securities.

 

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General Partner Interest and Incentive Distribution Rights

Our partnership agreement provides that our general partner initially will be entitled to 0.1% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest if we issue additional units. Our general partner’s 0.1% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately 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 0.1% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 0.1% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.

Incentive distribution rights represent the right to receive an increasing percentage (14.9% and 24.9%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement. The Funds collectively own, through non-voting membership interests in our general partner, 50.0% of the economic interest in our incentive distribution rights and of any common units issued to our general partner in connection with a reset of the incentive distribution rights.

The following discussion assumes that our general partner maintains its 0.1% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

If for any quarter:

 

  Ÿ  

we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

 

  Ÿ  

we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

 

  Ÿ  

first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until each unitholder receives a total of $0.54625 per unit for that quarter (the “first target distribution”);

 

  Ÿ  

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $0.59375 per unit for that quarter (the “second target distribution”); and

 

  Ÿ  

thereafter, 75.0% to all unitholders, pro rata, and 25.0% to our general partner.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the

 

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percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 0.1% general partner interest and assume there are no arrearages on common units and our general partner has contributed any additional capital to maintain its 0.1% general partner interest and our general partner has not transferred its incentive distribution rights.

 

    Total Quarterly Distribution
per Unit
    Marginal Percentage
Interest in Distributions
 
       Unitholders       General Partner   

Minimum Quarterly Distribution

    $0.4750        99.9     0.1

First Target Distribution

    above $0.4750 up to $0.54625        99.9     0.1

Second Target Distribution

    above $0.54625 up to $0.59375        85.0     15.0

Thereafter

    above $0.59375        75.0     25.0

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the special committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right (if at all) to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units and general partner units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters prior to the reset event as compared to the average cash distributions per common unit during this period. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us immediately prior to the reset election.

The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target

 

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distribution levels then in effect would be equal to the quotient determined by dividing (x) the average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the amount of cash distributed per common unit during each of these two quarters.

Following any reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

 

  Ÿ  

first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarterly distribution for that quarter;

 

  Ÿ  

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for the quarter; and

 

  Ÿ  

thereafter, 75.0% to all unitholders, pro rata, and 25.0% to our general partner.

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

We will make distributions of available cash from capital surplus, if any, in the following manner:

 

  Ÿ  

First, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until the minimum quarterly distribution is reduced to zero, as described below;

 

  Ÿ  

Second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

 

  Ÿ  

Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

The preceding discussion is based on the assumption that our general partner maintains its current general partner interest and that we do not issue additional classes of equity securities.

 

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Effect of a Distribution from Capital Surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from our initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in our initial public offering in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions as distributions from operating surplus, with 75.0% being paid to the holders of units and 25.0% to our general partner. The percentage interests shown for our general partner include its 0.1% general partner interest and assume our general partner has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, our partnership agreement specifies that the following items will be proportionately adjusted:

 

  Ÿ  

the minimum quarterly distribution;

 

  Ÿ  

target distribution levels;

 

  Ÿ  

the unrecovered initial unit price; and

 

  Ÿ  

the number of common units into which a subordinated unit is convertible.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, and each subordinated unit would be convertible into two common units. Our partnership agreement provides that we do not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental taxing authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters. In addition, as a result of a change in law or interpretation thereof, we or any of our subsidiaries is treated as an association taxable as a corporation or is otherwise subject to

 

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additional taxation as an entity for U.S. federal, state, local or non-U.S. income or withholding tax purposes, our general partner may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels by multiplying each by a fraction, the numerator of which is available cash for that quarter (after deducting our general partner’s estimate of our aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in laws or interpretation) and the denominator of which is the sum of available cash for that quarter plus our general partner’s estimate of our aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in laws or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

 

  Ÿ  

first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

 

  Ÿ  

second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

 

  Ÿ  

third, 99.9% to the subordinated unitholders, pro rata, and 0.1% to our general partner, until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

 

  Ÿ  

fourth, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each

 

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quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 99.9% to the unitholders, pro rata, and 0.1% to our general partner, for each quarter of our existence;

 

  Ÿ  

fifth, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence; and

 

  Ÿ  

thereafter, 75.0% to all unitholders, pro rata, and 25.0% to our general partner.

The percentage interests set forth above for our general partner include its 0.1% general partner interest and assume our general partner has not transferred the incentive distribution rights.

If the liquidation occurs after the end of the subordination period, the distinction between common and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

 

  Ÿ  

first, 99.9% to holders of subordinated units in proportion to the positive balances in their capital accounts and 0.1% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

 

  Ÿ  

second, 99.9% to the holders of common units in proportion to the positive balances in their capital accounts and 0.1% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

 

  Ÿ  

thereafter, 100.0% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. If we make positive adjustments to the capital accounts upon the issuance of additional units, then our partnership agreement requires that we allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

As of December 5, 2012, the following table sets forth the beneficial ownership of our common and subordinated units owned by:

 

  Ÿ  

each person known by us to be a beneficial owner of more than 5% of the then outstanding common units;

 

  Ÿ  

each director of our general partner;

 

  Ÿ  

each named executive officer of our general partner; and

 

  Ÿ  

all directors and named executive officers of our general partner as a group.

 

Name of Beneficial Owner (1)

  Common Units
Beneficially
Owned (2)
    Percentage of
Common Units
Beneficially
Owned (3)
    Subordinated
Units Beneficially
Owned
    Percentage of
Subordinated
Units Beneficially
Owned
    Percentage of
Total Common
and
Subordinated
Units Beneficially
Owned (3)
 

Memorial Resource (4)

    7,061,294        41.7     5,360,912        100    
55.7

Kenneth A. Hersh (5)

    7,061,294        41.7     5,360,912        100     55.7

Jonathan M. Clarkson

    10,921           *                       * 

Scott A. Gieselman

                                  

P. Michael Highum

    3,511           *                       * 

Tony R. Weber

                                  

Robert A. Innamorati (6)

    20,835           *                       * 

John A. Weinzierl (7)

    240,308        1.4                   1.1

Andrew J. Cozby

    39,285           *                       * 

Larry R. Forney

    28,759           *                       * 

Patrick T. Nguyen

    12,913           *                       * 

Kyle N. Roane

    5,105           *                       * 

Gregory M. Robbins

    10,663           *                       * 

All named executive officers and directors as a group (12 persons)

    7,433,594        43.9     5,360,912        100     57.4

 

* Less than 1.0%.
(1) The address for all beneficial owners in this table is 1301 McKinney, Suite 2100, Houston, Texas 77010.
(2) Includes common units purchased in the directed unit program at the closing of our initial public offering as well as restricted common units awarded under the Memorial Production Partners GP LLC Long-Term Incentive Plan.
(3) Based on 16,946,903 common units and 5,360,912 subordinated units outstanding.
(4) Memorial Resource is owned by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”), which also collectively directly own, through non-voting membership interests in our general partner, 50% of the economic interest in our incentive distribution rights. NGP VIII, NGP IX and NGP IX Offshore may be deemed to share voting and dispositive power over the reported securities; thus, each may also be deemed to be the beneficial owner of these securities. Each of NGP VIII, NGP IX and NGP IX Offshore disclaims beneficial ownership of the reported securities in excess of such entity’s respective pecuniary interest in the securities.
(5)

G.F.W. Energy VIII, L.P., GFW VIII, L.L.C., G.F.W. Energy IX, L.P. and GFW IX, L.L.C. may be deemed to beneficially own the units held by Memorial Resource that are attributable to NGP VIII, NGP IX and NGP IX Offshore by virtue of GFW VIII, L.L.C. being the sole general partner of G.F.W. Energy VIII, L.P. (which is the general partner of NGP VIII)

 

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  and GFW IX, L.L.C. being the sole general partner of G.F.W. Energy IX, L.P. (which is the general partner of NGP IX and NGP IX Offshore). Kenneth A. Hersh, one of our general partner’s directors and an Authorized Member of each of GFW VIII, L.L.C. and GFW IX, L.L.C., may also be deemed to share the power to vote, or to direct the vote, and to dispose, or to direct the disposition, of those units. Mr. Hersh does not own directly any common units or subordinated units.
(6) Includes 6,000 common units owned by the Robert A. Innamorati Trust, 300 common units owned by Mr. Innamorati’s spouse, 500 common units owned by Mr. Innamorati as custodian for his granddaughter’s UTMA account and 500 common units owned by Mr. Innamorati as custodian for his grandson’s UTMA account. Mr. Innamorati disclaims beneficial ownership of the reported securities in excess of his pecuniary interest in such securities.
(7) Includes 105,263 common units purchased in the directed unit program at the closing of our initial public offering by WCFB Interests, LP, a limited partnership that Mr. Weinzierl controls. Mr. Weinzierl disclaims beneficial ownership of the reported securities in excess of his pecuniary interest in such securities

Memorial Production Partners GP LLC, our general partner, owns all of our incentive distribution rights and a 0.1% general partner interest in us. The following table sets forth the approximate beneficial ownership of equity interests in our general partner.

 

Name of Beneficial Owner

   Class A
Member
Interest (a)
    Class B
Member
Interest (a)
 

Memorial Resource (b)

     100       

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

            50.3

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

            47.3

NGP IX Offshore Holdings, L.P. (c)(d)

            2.4

 

(a) Our general partner has two classes of member interests. Memorial Resource owns the voting Class A member interest, and will be entitled to 50% of any cash distributions made or common units issued to our general partner with respect to our general partner’s 0.1% general partner interest in us. NGP VIII, NGP IX and NGP IX Offshore own approximately 50.3%, 47.3% and 2.4%, respectively, of the non-voting Class IDR member interest in our general partner, which entitles them to an aggregate 50% of any cash distributions made or common units issued to our general partner.
(b) Our general partner is controlled by Memorial Resource, which is controlled by NGP VIII, NGP IX and NGP IX Offshore. Mr. Hersh will share in distributions made by us with respect to interests held by our general partner in proportion to his pecuniary interests. Mr. Hersh disclaims beneficial ownership of the reported securities in excess of his pecuniary interest in such securities. In addition, our general partner’s other non-independent directors and certain of our general partner’s executive officers have indirect financial interests in Memorial Resource and its affiliates.
(c) NGP VIII, NGP IX and NGP IX Offshore may be deemed to share voting and dispositive power over the reported interests of Memorial Resource; thus, each of NGP VIII, NGP IX and NGP IX Offshore may also be deemed to be the beneficial owner of these interests. Each of NGP VIII, NGP IX and NGP IX Offshore disclaims beneficial ownership of such reported interests in excess of such entity’s respective pecuniary interest in such interests. G.F.W. Energy VIII, L.P., GFW VIII, L.L.C., G.F.W. Energy IX, L.P. and GFW IX, L.L.C. may be deemed to beneficially own the interests owned by Memorial Resource attributable to NGP VIII, NGP IX and NGP IX Offshore and the interests held by NGP VIII, NGP IX and NGP IX Offshore by virtue of GFW VIII, L.L.C. being the sole general partner of G.F.W. Energy VIII, L.P. (which is the general partner of NGP VIII) and GFW IX, L.L.C. being the sole general partner of G.F.W. Energy IX, L.P. (which is the general partner of NGP IX and NGP IX Offshore). Kenneth A. Hersh, one of our general partner’s directors and an Authorized Member of each of GFW VIII, L.L.C. and GFW IX, L.L.C., may also be deemed to share the power to vote, or to direct the vote, and to dispose, or to direct the disposition, of the interests held by NGP VII, NGP IX and NGP IX Offshore. Mr. Hersh does not own directly any interests in our general partner.
(d) The address for NGP VIII, NGP IX and NGP IX Offshore is 125 E. John Carpenter Fwy., Suite 600, Irving, Texas 75602.

Memorial Resource has pledged 7,061,294 of our common units and 5,360,912 of our subordinated units, as well as its ownership interest in our general partner, as security under its senior secured revolving credit facility in addition to certain other assets of Memorial Resource. This credit facility contains customary and other events of default relating to defaults of Memorial Resource. If Memorial Resource were to default under its credit facility, Memorial Resource’s lenders could exercise their rights over the pledged collateral, which could result in a change in control of our general partner and a change in control of us.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Immediately following this offering, assuming the underwriters do not exercise their option to purchase additional common units, Memorial Resource will control our general partner and own approximately 25.7% of our outstanding common units and all of our subordinated units. Memorial Resource owns 100% of the voting membership interests in our general partner, and the Funds own non-voting membership interests in our general partner that entitle them collectively to 50% of all cash distributions and common units received by our general partner in respect of our incentive distribution rights. Our general partner owns a 0.1% general partner interest in us, which will be evidenced by 32,840 general partner units immediately following this offering assuming the underwriters do not exercise their option to purchase additional common units, and all of our incentive distribution rights.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, were not the result of arm’s-length negotiations.

Formation Stage

 

The consideration received by our general partner and Memorial Resource prior to or in connection with our initial public offering  

Ÿ     7,061,294 common units;

 

Ÿ     5,360,912 subordinated units;

 

Ÿ     22,044 general partner units;

 

Ÿ     all of our incentive distribution rights; and

 

Ÿ     approximately $280 million in cash.

Operational Stage

 

Distributions of available cash to our general partner and its affiliates

Prior to this offering, we generally have made cash distributions to our common and subordinated unitholders and general partner pro rata, including our general partner and its affiliates, as the holders of 7,061,294 common units, all of the subordinated units and 22,330 general partner units.

 

  For the nine months ended September 30, 2012, our general partner and its affiliates received an aggregate of $13.1 million in cash distributions from us, which consisted of $7.4 million in respect of common units owned by Memorial Resource, $5.6 million in respect of subordinated units owned by Memorial Resource and $0.1 million in respect of our general partner units.

 

  If distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner is entitled to increasing percentages of the distributions, up to a maximum of 25.0% of the distributions above the highest target distribution level, including the general partner’s 0.1% general partner interest.

 

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Payments to our general partner and its affiliates

Our general partner does not receive a management fee or other compensation for its management of our partnership, but we reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner and its affiliates in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the amount of such expenses that are allocable to us.

 

  For the nine months ended September 30, 2012, we reimbursed our general partner and its affiliates an aggregate of $1.2 million for all direct and indirect expenses incurred or payments made on our behalf and all other expenses allocable to us or otherwise incurred in connection with operating our business.

 

Withdrawal or removal of our general partner

If our general partner is removed under circumstances where cause exists or withdraws and such withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest in us and the incentive distribution rights for a cash payment equal to the fair market value of those interests. Under all other circumstances in which our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the departing general partner’s general partner interest in us and its incentive distribution rights for their fair market value or to convert such interests into common units.

Liquidation Stage

 

Liquidation

Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

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

Memorial Production Partners GP LLC, our general partner and a wholly-owned subsidiary of Memorial Resource, owns a 0.1% general partner interest in us. Under our general partner’s amended and restated limited liability company agreement, our general partner has the following two classes of membership interests:

 

  Ÿ  

Class A—Memorial Resource owns all of the Class A membership interests in our general partner. The Class A membership interests are the sole voting interests in our general

 

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partner and entitle Memorial Resource, as the Class A member, to all distributions we make to our general partner (including distributions with respect to our general partner’s 0.1% general partner interest in us), other than those distributions payable to the Class IDR members described below.

 

  Ÿ  

Class IDR—The Funds own all of the non-voting, Class IDR membership interests in our general partner. The holders of the Class IDR membership interests are entitled to receive (i) an aggregate of 50% of all cash received by our general partner from us attributable to distributions related to the incentive distribution rights, (ii) 50% of any common units issued to our general partner in connection with any reset of the incentive distribution levels and (iii) 50% of any cash, securities or other proceeds received by our general partner pursuant to a sale or transfer of the incentive distribution rights.

Subject to certain conditions, a member may transfer, pledge or assign all or any portion of its membership interest in our general partner at any time.

Related Party Agreements

We and certain of our affiliates have entered into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations.

Purchase and Sale Agreement and Contribution, Conveyance and Assumption Agreements

On December 14, 2011, in connection with the closing of our initial public offering, we entered into a purchase and sale agreement and two contribution, conveyance and assumption agreements with Memorial Resource and certain of its subsidiaries that effected, among other things, the following transactions:

 

  Ÿ  

Memorial Resource caused certain of its subsidiaries to contribute a 100% membership interest in Columbus Energy LLC, a Delaware limited liability company, to us in exchange for the right to receive (i) 4,619,598 common units, (ii) 3,507,184 subordinated units and (iii) a distribution of approximately $132.6 million;

 

  Ÿ  

Memorial Resource caused one of its subsidiaries to sell certain oil and natural gas properties and related assets to us in exchange for the right to receive cash equal to approximately $71.0 million; and

 

  Ÿ  

Memorial Resource caused one of its subsidiaries to contribute certain oil and natural gas properties and related assets to ETX I LLC, a Delaware limited liability company (“ETX”), and then contribute a 100% membership interest in ETX to us in exchange for the right to receive (i) 2,441,696 common units, (ii) 1,853,728 subordinated units and (iii) a distribution of approximately $68.3 million.

Omnibus Agreement

On December 14, 2011, in connection with the closing of our initial public offering, we entered into an omnibus agreement with our general partner and Memorial Resource.

Pursuant to the omnibus agreement, we are required to reimburse Memorial Resource for all expenses incurred by Memorial Resource (or payments made on our behalf) in conjunction with its provision of general and administrative services to us, including, but not limited to, our public

 

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company expenses and an allocated portion of the salary and benefits of the executive officers of our general partner and other employees of Memorial Resource who perform services for us or on our behalf. We are also obligated to reimburse Memorial Resource for insurance coverage expenses it incurs with respect to our business and operations and with respect to director and officer liability coverage for the officers and directors of our general partner.

Pursuant to the omnibus agreement, Memorial Resource has agreed to indemnify our general partner and us against (i) title defects, (ii) income taxes attributable to pre-closing ownership or operation of the assets we acquired in connection with our initial public offering, including any income tax liabilities related to such acquisition occurring on or prior to the closing of our initial public offering, (iii) environmental claims, losses and expenses associated with the operation of our business prior to the closing of our initial public offering, subject to a maximum indemnification amount of $5,000,000, (iv) all liabilities other than covered environmental liabilities, relating to the operation of such assets prior to the closing of our initial public offering that were not disclosed in the most recent pro forma balance sheet included in the prospectus for our initial public offering, or incurred in the ordinary course of business thereafter, subject to a maximum indemnification amount of $5,000,000, and (v) all losses arising as a result of the failure of Memorial Resource to obtain by closing of our initial public offering any consent, waiver or permit necessary for us to own and operate such assets.

Memorial Resource’s indemnification obligation will (i) survive for three years after the closing of our initial public offering with respect to consents and title defects, (ii) survive for one year after the closing of our initial public offering with respect to environmental claims and other undisclosed pre-closing liabilities and (iii) survive for sixty days after the expiration of the applicable statute of limitations with respect to income taxes. All claims (other than income tax claims) are subject to a $50,000 per claim de minimus exception, environmental claims are subject to a $500,000 deductible, and claims relating to other pre-closing undisclosed liabilities, title or consents are subject to an aggregate $500,000 deductible.

Pursuant to the omnibus agreement, we must indemnify Memorial Resource for any liabilities incurred by Memorial Resource attributable to the operating and administrative services provided to us under the omnibus agreement, other than liabilities resulting from Memorial Resource’s bad faith or willful misconduct. In addition, Memorial Resource must indemnify us for any liability we incur as a result of Memorial Resource’s bad faith or willful misconduct in providing operating and administrative services under the omnibus agreement. Memorial Resource may terminate the omnibus agreement in the event that it ceases to be an affiliate of us and may also terminate the omnibus agreement if we fail to pay amounts due thereunder in accordance with its terms.

Under the omnibus agreement, none of the parties thereto nor any of their respective affiliates have any obligation to offer, or provide any opportunity to pursue, purchase or invest in, any business opportunity to any other party or their affiliates. Furthermore, the omnibus agreement does not restrict any of the parties thereto and their respective affiliates from competing with either Memorial Resource or our general partner and us.

Tax Sharing Agreement

On December 14, 2011, in connection with the closing of our initial public offering, we entered into a tax sharing agreement with Memorial Resource pursuant to which we are required to reimburse Memorial Resource for our share of state and local income and other taxes borne by Memorial Resource as a result of our results being included in a combined or consolidated tax return filed by Memorial Resource or its affiliates with respect to periods after the closing of our initial public offering. Under the tax sharing agreement, Memorial Resource may use its tax

 

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attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe no tax. However, we would nevertheless be required to reimburse Memorial Resource for the tax we would have owed had the attributes not been available or used for our benefit, even though Memorial Resource had no cash expense for that period.

Acquisitions of Oil and Natural Gas Producing Properties

April Acquisition. On April 2, 2012, we acquired certain oil and natural gas producing properties, located primarily in the Willow Springs field in Gregg County, as well as in Upshur, Rusk, Panola, Smith and Leon counties in East Texas, from an operating subsidiary of Memorial Resource for a purchase price of $18.5 million, subject to customary post-closing adjustments. This transaction, which also included the novation to us of 2012 through 2013 commodity derivative positions, was financed with borrowings under our revolving credit facility.

Memorial Resource, the parent of the seller in that transaction, is owned by the Funds, and each of Messrs. Hersh, Weber, Gieselman and Weinzierl have indirect economic interests in the Funds that entitle them to a portion of the profits generated by the Funds in excess of certain return thresholds. The transaction was approved by the board of directors of our general partner and by its conflicts committee, which is comprised entirely of independent directors.

May Acquisition. On May 14, 2012, we acquired certain oil and natural gas producing properties, located primarily in the Cotton Valley and Travis Peak fields in Panola and Shelby counties in East Texas, from an operating subsidiary of Memorial Resource for a purchase price of $27.0 million, subject to customary post-closing adjustments. This transaction, which also included the novation to us of 2012 through 2014 commodity derivative positions, was financed with borrowings under our revolving credit facility.

Memorial Resource, the parent of the seller in that transaction, is owned by the Funds, and each of Messrs. Hersh, Weber, Gieselman and Weinzierl have indirect economic interests in the Funds that entitle them to a portion of the profits generated by the Funds in excess of certain return thresholds. The transaction was approved by the board of directors of our general partner and by its conflicts committee, which is comprised entirely of independent directors.

Beta Acquisition. On November 19, 2012, we, through a wholly-owned subsidiary, entered into a purchase and sale agreement pursuant to which we agreed to purchase all of the outstanding equity interests in Rise Energy Operating, LLC and its subsidiaries, which collectively own certain oil and gas producing properties and assets offshore Southern California, for approximately $271 million, including $3 million of working capital and other customary adjustments. We expect to finance the acquisition with cash on hand, borrowings under our revolving credit facility, the net proceeds from this offering and, potentially, promissory notes payable to the seller. Please read “Beta Acquisition.”

The seller in the Beta transaction is owned by two of the Funds, and each of Messrs. Hersh, Weber, Gieselman and Weinzierl have indirect economic interests in those Funds that entitle them to a portion of the profits generated by those Funds in excess of certain return thresholds. The transaction was approved by the board of directors of our general partner and by its conflicts committee, which is comprised entirely of independent directors.

Review, Approval or Ratification of Transactions with Related Persons

The board of directors of our general partner has adopted a Code of Business Conduct and Ethics that sets forth our policies for the review, approval and ratification of transactions with related persons. Pursuant to the Code of Business Conduct and Ethics, a director is expected to

 

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bring to the attention of the Chief Executive Officer or the board of directors of our general partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict will be addressed in accordance with Memorial Resource’s and our general partner’s organizational documents and the provisions of our partnership agreement. The resolution may be determined by disinterested directors, our general partner’s board of directors, or the conflicts committee of our general partner’s board of directors. Our Code of Business Conduct and Ethics is available within the “Corporate Governance” section of our website at http://investor.memorialpp.com/governance.cfm.

Under the Code of Business Conduct and Ethics, any executive officer of our general partner is required to avoid conflicts of interest unless approved by the board of directors. The board of directors of our general partner currently has a conflicts committee comprised of three independent directors. Our general partner may, but is not required to, seek the approval of a conflicts committee in connection with future acquisitions from (or other transactions with) Memorial Resource or any of its affiliates. In the case of any sale of equity or debt by us to Memorial Resource or any of its affiliates, we anticipate that our practice will be to obtain the approval of the conflicts committee for the transaction. The conflicts committee is entitled to hire its own financial and legal advisors in connection with any matters on which the board of directors of our general partner has sought the conflicts committee’s approval.

Memorial Resource and its affiliates is free to offer properties to us on terms it or they deem acceptable, and the board of directors of our general partner (or the conflicts committee) is free to accept or reject any such offers, negotiating terms it deems acceptable to us. As a result, the board of directors of our general partner (or the conflicts committee) will decide, in its sole discretion, the appropriate value of any assets offered to us by Memorial Resource or its affiliates. In so doing, we expect the board of directors (or the conflicts committee) will consider a number of factors in its determination of value, including, without limitation, production and reserve data, operating cost structure, current and projected cash flows, financing costs, the anticipated impact on distributions to our unitholders, production decline profile, commodity price outlook, reserve life, future drilling inventory and the weighting of the expected production between oil and natural gas.

We expect that Memorial Resource and its affiliates will consider a number of the same factors considered by the board of directors of our general partner to determine the proposed price for any assets it or they may offer to us in future periods. In addition to these factors, given that Memorial Resource is our largest unitholder and considering its and the Funds’ interest in our incentive distribution rights, it and they may consider the potential positive impact on their underlying investment in us by offering properties to us at attractive purchase prices. Likewise, it and they may consider the potential negative impact on their underlying investment in us if we are unable to acquire additional assets on favorable terms, including the negotiated purchase price.

 

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Memorial Resource, the Funds, and NGP) on the one hand, and us and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. In addition, many of the directors and officers of our general partner serve in similar capacities with Memorial Resource and the Funds and their respective affiliates, and certain of our executive officers and directors have economic interests, investments and other economic incentives in entities affiliated with the Funds, which may lead to additional conflicts of interest. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to us and our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

 

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approved by the conflicts committee, although our general partner is not obligated to seek such approval;

 

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approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

 

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on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

 

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fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

As provided by our partnership agreement, conflicts of interest may be resolved by approval of a committee of the board of directors of our general partner comprised of independent directors. From time to time, the board of directors of our general partner may refer a potential conflict of interest to the conflicts committee, which is currently comprised of three independent directors.

Our general partner may, but is not required to, seek approval from the conflicts committee of a resolution of a conflict of interest with our general partner or affiliates. If our general partner seeks approval from the conflicts committee, the conflicts committee may determine the resolution of a conflict of interest with our general partner or its affiliates. Any matters approved by the conflicts committee in good faith will be deemed to be approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the

 

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standards set forth in the third or fourth bullet points above, then it will be presumed that, in making its decision, the 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. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to have an honest belief that he or she is acting in our best interest.

Conflicts of interest could arise in the situations described below, among others:

Memorial Resource, the Funds and other affiliates of our general partner are not 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.

Because Memorial Resource controls our general partner and also is permitted to compete with us, Memorial Resource could choose to acquire properties and pursue opportunities that would have been suitable for our partnership. In such a case, Memorial Resource would have the benefit of any such opportunity instead of us.

NGP and its affiliates (including 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.

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.

Because the officers and certain of the directors of our general partner are also officers and/or directors of Memorial Resource, the Funds and their respective affiliates, such officers and directors have fiduciary duties to Memorial Resource, the Funds and their respective affiliates that may cause them to pursue business strategies that disproportionately benefit Memorial Resource, the Funds and their respective affiliates or which otherwise are not in our best interests.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to our general partner or any of its affiliates, including its officers, directors, Memorial Resource, the Funds or any of their affiliates. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary for itself, directs such opportunity to another person or entity or does not communicate

 

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such opportunity or information to us. Therefore, Memorial Resource, the Funds and their affiliates may compete with us for investment opportunities.

Moreover, Memorial Resource is 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. 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.

Our general partner is allowed to take into account the interests of parties other than us in resolving conflicts of interest.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. 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 our general partner’s limited call right, its registration rights, its determination whether or not to consent to any merger or consolidation involving us, and its decision to convert its incentive distribution rights into common units.

Many of the directors and all of the officers who have responsibility for our management have significant duties with, and 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.

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) 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. Officers of our general partner 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

 

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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.

Neither we nor our general partner have any employees and we rely solely on the employees of Memorial Resource to manage our business. The management team of Memorial Resource also performs substantially similar services for Memorial Resource, which owns and operates 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. Pursuant to the omnibus agreement with Memorial Resource, Memorial Resource agreed, among other things, to make available to our general partner Memorial Resource’s personnel in a manner that will allow us to carry on our business in the same manner in which it was carried on by our predecessor.

Memorial Resource provides substantially similar services with respect to its own assets and operations. Because Memorial Resource provides services to us that are substantially similar to those provided to 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 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 partnership agreement limits our general partner’s fiduciary duties to holders of our units and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

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:

 

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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its right to reset the target distribution levels of its incentive distribution rights at higher levels and receive, in connection with this reset, common units, the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation involving us or to any amendment to the partnership agreement;

 

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provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith;

 

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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must

 

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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;

 

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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

 

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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.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business, including, but not limited to, the following:

 

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the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

 

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the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and unit appreciation rights relating to our securities;

 

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the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

 

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the negotiation, execution and performance of any contracts, conveyances or other instruments;

 

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the distribution of our cash;

 

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the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

 

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the maintenance of insurance for our benefit and the benefit of our partners;

 

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the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other entities;

 

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the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

 

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the indemnification of any person against liabilities and contingencies to the extent permitted by law;

 

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the making of tax, regulatory and other filings or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

 

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the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement further 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 “The Partnership Agreement—Limited Voting Rights” for information regarding matters that require unitholder approval.

Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership interests and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

 

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the manner in which our business is operated;

 

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the amount, nature and timing of asset purchases and sales;

 

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the amount, nature and timing of our capital expenditures;

 

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the amount of borrowings;

 

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the issuance of additional units; and

 

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the creation, reduction or increase of reserves in any quarter.

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or 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 and the ability of the subordinated units to convert into common units.

In addition, our general partner may use an amount, initially equal to $30.5 million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

 

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In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights or enabling the expiration of the subordination period.

For example, if we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units.

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us or our operating subsidiaries.

Our general partner determines which costs incurred by it are reimbursable by us.

We reimburse our general partner and its affiliates for costs incurred in managing and operating our business, including costs incurred in rendering staff and support services to us. Our partnership agreement provides that our general partner determines the expenses that are allocable to us in good faith.

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 partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with Memorial Resource, the Funds or their respective affiliates on our behalf. Similarly, agreements, contracts or arrangements between us and our general partner, Memorial Resource, the Funds or their respective affiliates are not required to be negotiated on an arms-length basis, although, in some circumstances, our general partner may determine that the conflicts committee of our general partner may make a determination on our behalf with respect to one or more of these types of situations.

Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.

Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner or its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

Our general partner may exercise its right to call and purchase common units as provided in our partnership agreement or assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The Partnership Agreement—Limited Call Right.”

 

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Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner, Memorial Resource, the Funds and their respective affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner, Memorial Resource, the Funds and their respective affiliates in our favor.

Our general partner and Memorial Resource may be able to amend our partnership agreement without the approval of any other unitholder after the subordination period.

Our general partner has the discretion to propose amendments to our partnership agreement, certain of which may be made by our general partner without unitholder approval. Our partnership agreement generally may not be otherwise amended during the subordination period without the approval of a majority of our public common unitholders. However, after the subordination period has ended, 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). Memorial Resource owns our general partner and all of our subordinated units. Immediately following this offering and assuming the underwriters do not exercise their option to purchase additional common units, Memorial Resource will own and control the voting of an aggregate of approximately 25.7% of our outstanding common units. Assuming that Memorial Resource retains a sufficient number of its common units and that we do not issue additional common units, our general partner and Memorial Resource will have the ability to amend our partnership agreement without the approval of any other unitholder after the subordination period. Please read “The Partnership Agreement—Amendment of the Partnership Agreement.”

Our general partner intends to limit its liability regarding our obligations.

Our general partner will enter into contractual arrangements on our behalf and intends to limit its liability under such contractual arrangements so that the other party has recourse only to our assets and not against our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s-length negotiations.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself, Memorial Resource, the Funds and their respective for any services rendered to us. Our general partner may also enter into contractual arrangements with Memorial Resource, the Funds and their respective affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our general partner, Memorial Resource, the Funds and their respective affiliates, on the other, are or will be the result of arm’s-length negotiations.

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

The attorneys, independent accountants and others who have performed services for us in connection with this offering have been retained by our general partner. The attorneys, independent accountants and others who perform services for us are selected by our general

 

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partner, or the conflicts committee of our general partner’s board of directors, and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of our common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of our common units, on the other, depending on the nature of the conflict. We do not intend to hire separate counsel to represent us or the holders of our common units in most cases.

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%, assuming it has maintained its 0.1% general partner interest) 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.

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 we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict, eliminate or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to

 

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allow our general partner, Memorial Resource, the Funds and their respective affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner’s board of directors has fiduciary duties to manage our general partner in a manner beneficial to its owners, as well as to our unitholders. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable our general partner to take into consideration the interests of all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to our common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest.

The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

 

State-law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

 

Rights and remedies of unitholders

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third-party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

 

Partnership agreement modified standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under

 

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applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.

 

  In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct, or in the case of a criminal matter, acted with the knowledge that such conduct was unlawful.

 

  Special Provisions Regarding Affiliate Transactions. Our partnership agreement generally provides that affiliate transactions and resolutions of conflicts of interest that are not approved by vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be:

 

   

on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

 

   

“fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

 

  If our general partner does not seek approval from the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

By purchasing our common units, each unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render our partnership agreement unenforceable against that person.

 

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Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement—Indemnification.”

 

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “Provisions of Our Partnership Agreement Relating to Cash Distributions.” For a description of other rights and privileges of limited partners under our partnership agreement, including limited voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Duties

Wells Fargo Shareowner Services serves as registrar and transfer agent for our common units. We will pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by our unitholders:

 

  Ÿ  

surety bond premiums to replace lost or stolen certificates or to cover taxes and other governmental charges;

 

  Ÿ  

special charges for services requested by a common unitholder; and

 

  Ÿ  

other similar fees or charges.

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of their actions for their activities in that capacity, except for any liability due to any gross negligence or willful misconduct of the indemnitee.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units will be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

 

  Ÿ  

represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

 

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automatically agrees to be bound by the terms and conditions of our partnership agreement; and

 

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  Ÿ  

gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units. A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and any transfers are subject to the laws governing transfers of securities.

 

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. Our partnership agreement has been filed with the SEC and is incorporated by reference in this prospectus. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

 

  Ÿ  

with regard to distributions of available cash, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions”;

 

  Ÿ  

with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties”;

 

  Ÿ  

with regard to the transfer of common units, please read “Description of the Common Units—Transfer of Common Units”; and

 

  Ÿ  

with regard to allocations of taxable income, taxable loss and other matters, please read “Material Tax Consequences.”

Organization and Duration

We were organized in April 2011 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose under our partnership agreement is to engage in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law. However, our general partner may not cause us to engage in any business activity that it determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the ownership, acquisition, exploitation and development of oil and natural gas properties and the ownership, acquisition and operation of related assets, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Cash Distributions

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest. For a description of these cash distribution provisions, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.” Our general partner has the right, but not the obligation, to

 

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contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest in us if we issue additional units. Our general partner’s 0.1% interest in us, and the percentage of our cash distributions to which it is entitled, will be proportionately 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 0.1% general partner interest. To maintain its 0.1% general partner interest in us, our general partner will be entitled to make capital contributions in the form of common units based on the then-current market value of the contributed common units.

Limited Voting Rights

The following is a summary of the unitholder vote required for each of the matters specified below.

Various matters require the approval of a “unit majority,” which means:

 

  Ÿ  

during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, each voting as a separate class; and

 

  Ÿ  

after the subordination period, the approval of a majority of the outstanding common units.

By virtue of the exclusion of those common units held by our general partner and its affiliates from the required vote, and by their ownership of all of the subordinated units, during the subordination period, our general partner and its affiliates do not have the ability to ensure passage of, but do have the ability to ensure defeat of, any amendment that requires a unit majority.

In voting their common units and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.

 

Issuance of additional units

No approval right. Please read “—Issuance of Additional Securities.”

 

Amendment of the partnership agreement

Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of the Partnership Agreement.”

 

Merger of our partnership or the sale of all or substantially all of our assets

Unit majority, in certain circumstances. Please read “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

 

Dissolution of our partnership

Unit majority. Please read “—Termination and Dissolution.”

 

Continuation of our business upon dissolution

Unit majority. Please read “—Termination and Dissolution.”

 

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Withdrawal of our general partner

Prior to September 30, 2021, under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”

 

Removal of our general partner

Not less than 66 2/3% of the outstanding units, including units held by our general partner and its affiliates. Please read “—Withdrawal or Removal of Our General Partner.”

 

Transfer of our general partner interest

Our general partner may transfer without a vote of our unitholders all, but not less than all, of its general partner interest in us to an affiliate or another person (other than an individual) in connection with its merger or consolidation with or into, or sale of all, or substantially all, of its assets, to such person. The approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third-party prior to September 30, 2021. Please read “—Transfer of General Partner Units.”

 

Transfer of incentive distribution rights

No approval rights. Please read “—Transfer of Incentive Distribution Rights.”

 

Transfer of ownership interests in our general partner

No approval required. Please read “—Transfer of Ownership Interests in Our General Partner.”

Applicable Law; Forum, Venue and Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

 

  Ÿ  

arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

 

  Ÿ  

brought in a derivative manner on our behalf;

 

  Ÿ  

asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

 

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asserting a claim arising pursuant to any provision of the Delaware Act; or

 

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asserting a claim governed by the internal affairs doctrine,

 

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shall be exclusively brought in the Court of Chancery of the State of Delaware, regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claims, suits, actions or proceedings.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right or exercise of the right, by our limited partners as a group:

 

  Ÿ  

to remove or replace our general partner;

 

  Ÿ  

to approve some amendments to the partnership agreement; or

 

  Ÿ  

to take other action under the partnership agreement

constituted “participation in the control” of our business for the purposes of the Delaware Act, then our limited partners could be held personally liable for our obligations under Delaware law, to the same extent as our general partner. This liability would extend to persons who transact business with us and reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. Moreover, under the Delaware Act, a limited partnership may also not make a distribution to a partner upon the winding up of the limited partnership before liabilities of the limited partnership to creditors have been satisfied by payment or the making of reasonable provision for payment thereof. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Our operating subsidiary currently conducts business in Texas and Louisiana, and we may have operating subsidiaries that conduct business in other states in the future. Maintenance of our

 

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limited liability as a member of each of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which our operating subsidiaries conduct business, including qualifying our operating subsidiaries to do business there.

Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. If, by virtue of our ownership in the operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by our limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then our limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of our limited partners.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of our unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special limited voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to our common units.

If we issue additional units in the future, our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 0.1% general partner interest in us. Our general partner’s 0.1% general partner interest in us will 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 0.1% general partner interest in us. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the aggregate percentage interest in us of our general partner and its affiliates, including such interest represented by common units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner has no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or

 

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our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. To adopt a proposed amendment, other than the amendments discussed below under “—No Unitholder Approval,” our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of our limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

 

  Ÿ  

enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

 

  Ÿ  

enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion.

The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Immediately following this offering, Memorial Resource will own approximately 25.7% of our outstanding common units and all of our subordinated units, representing an aggregate 37.8% limited partner interest in us.

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner or assignee to reflect:

 

  Ÿ  

a change in our name, the location of our principal place of business, our registered agent or our registered office;

 

  Ÿ  

the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

 

  Ÿ  

a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state or to ensure that neither we, nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

 

  Ÿ  

a change in our fiscal year or taxable year and related changes;

 

  Ÿ  

an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or the directors, officers, agents or trustees of our general partner from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

 

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  Ÿ  

an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities;

 

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any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

 

  Ÿ  

an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

 

  Ÿ  

any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

 

  Ÿ  

any amendment necessary to require our limited partners to provide a statement, certification or other evidence to us regarding whether such limited partner is subject to United States federal income taxation on the income generated by us and to provide for the ability of our general partner to redeem the units of any limited partner who fails to provide such statement, certification or other evidence;

 

  Ÿ  

conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

 

  Ÿ  

any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

 

  Ÿ  

do not adversely affect our limited partners (or any particular class of limited partners) in any material respect;

 

  Ÿ  

are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

 

  Ÿ  

are necessary or appropriate to facilitate the trading of our limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which our limited partner interests are or will be listed for trading;

 

  Ÿ  

are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

 

  Ÿ  

are required to effect the intent expressed in this prospectus or the intent of the provisions of the partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

For amendments of the type not requiring unitholder approval, our general partner is not required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to our limited partners or result in our being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. No other

 

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amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units requires the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Any amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased.

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

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner has no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interest of us or our limited partners.

In addition, the partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or sale, exchange or other disposition of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without the approval of a unit majority. Finally, our general partner may consummate any merger, consolidation or conversion without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction will not result in a material amendment to our partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction, and the partnership securities to be issued do not exceed 20% of our outstanding partnership securities immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide our limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. The unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

 

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Termination and Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:

 

  Ÿ  

the election of our general partner to dissolve us, if approved by the holders of a unit majority;

 

  Ÿ  

there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

 

  Ÿ  

the entry of a decree of judicial dissolution of our partnership; or

 

  Ÿ  

the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in us in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by a unit majority, subject to our receipt of an opinion of counsel to the effect that:

 

  Ÿ  

the action would not result in the loss of limited liability under Delaware law of any limited partner; and

 

  Ÿ  

neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to September 30, 2021 without obtaining the approval of the holders of at least a majority of our outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after September 30, 2021, our general partner may withdraw as our general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw as our general partner without unitholder approval upon 90 days’ notice to our limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its

 

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affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “—Transfer of General Partner Units.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a majority of our outstanding units may select a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a majority of our outstanding common units, excluding the common units held by the withdrawing general partner and its affiliates, agree in writing to continue our business and to appoint a successor general partner. Please read “—Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% of our outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of our outstanding common units, including common units held by our general partner and its affiliates. The ownership of more than 33 1/3% of our outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. Immediately following this offering, Memorial Resource will own approximately 25.7% of our outstanding common units and 100% of our subordinated units, representing an aggregate 37.8% limited partner interest in us.

Our partnership agreement also provides that if our general partner is removed as our general partner without cause and no units held by our general partner and its affiliates are voted in favor of that removal:

 

  Ÿ  

the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

 

  Ÿ  

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

 

  Ÿ  

our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of the interests at the time.

In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest and incentive distribution rights for a cash payment equal to the fair market value of that interest. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the departing general partner’s general partner interest and incentive distribution rights for its fair market value.

In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. If the departing general partner

 

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and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and incentive distribution rights will automatically convert into common units equal to the fair market value of that interest as determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Units

Except for the transfer by our general partner of all, but not less than all, of its general partner units to:

 

  Ÿ  

an affiliate of our general partner (other than an individual); or

 

  Ÿ  

another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

our general partner may not transfer all or any part of its general partner units to another person, prior to September 30, 2021, without the approval of the holders of at least a majority of our outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time transfer common units or subordinated units to one or more persons without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Incentive Distribution Rights

Our general partner or any other holder of incentive distribution rights may transfer any or all of its incentive distribution rights without unitholder approval.

Transfer of Ownership Interests in Our General Partner

At any time, the owner of our general partner may sell or transfer all or part of its membership interest in our general partner to an affiliate or a third party without the approval of our unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change the

 

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management of our general partner. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses limited voting rights on all of its units. This loss of limited voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of our then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:

 

  Ÿ  

the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

 

  Ÿ  

the current market price as of the date three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The federal income tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Tax Consequences—Disposition of Common Units.”

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. In the case of common units held by the general partner on behalf of non-citizen assignees, the general partner will distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting, if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

 

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Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special limited voting rights could be issued. Please read “—Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose limited voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of any common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Except as described above under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Citizen Assignees; Redemption

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 that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we may redeem the units held by the limited partner at their current market price. (This could occur, for example, if in the future we own interests in oil and natural gas leases on United States federal lands.) In order to avoid any cancellation or forfeiture, 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, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. 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.

In addition, in such circumstance, we will have the right to acquire all (but not less than all) of the units held by such limited partner or non-citizen assignee. The purchase price for such units will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for such purchase, and such purchase price will be paid (in the sole discretion of our general partner) either in cash or by delivery of a promissory note. Any such promissory note will bear interest at the rate of 5% annually and will be payable in three equal annual installments of principal and accrued interest, commencing one year after the purchase date. Any such promissory note will also be unsecured and will be subordinated to the extent required by the terms of our other indebtedness.

 

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Non-Taxpaying Assignees; Redemption

If our general partner, with the advice of counsel, 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 necessary or advisable to:

 

  Ÿ  

obtain proof of the U.S. federal income tax status of limited partners (and their owners, to the extent relevant); and

 

  Ÿ  

permit us to redeem the units at their current market price held by any person whose tax status has or is reasonably likely to have a material adverse effect on our ability to operate our assets or generate revenues from our assets or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status.

A non-taxpaying assignee does not have the right to direct the voting of his units and may not receive distributions in-kind upon our liquidation.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

 

  Ÿ  

our general partner;

 

  Ÿ  

any departing general partner;

 

  Ÿ  

any person who is or was an affiliate of a general partner or any departing general partner;

 

  Ÿ  

any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;

 

  Ÿ  

any person who is or was serving as a director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and

 

  Ÿ  

any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance covering liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These

 

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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 general partner is entitled to determine in good faith the expenses that are allocable to us.

Pursuant to the omnibus agreement, Memorial Resource has agreed, among other things, to provide the administrative, management, and acquisition advisory services that we believe are necessary to allow our general partner to manage, operate and grow our business, as well as the operating services that we believe are necessary to develop and operate our properties.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For financial reporting and tax purposes, our fiscal year end is December 31.

We will furnish or make available to record holders of common units, within 90 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent registered public accounting firm. Except for our fourth quarter, we will also furnish or make available summary financial information within 45 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website which we maintain.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on the cooperation of our unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, obtain:

 

  Ÿ  

a current list of the name and last known address of each partner;

 

  Ÿ  

a copy of our tax returns;

 

  Ÿ  

information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;

 

  Ÿ  

copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

 

  Ÿ  

information regarding the status of our business and financial condition; and

 

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any other information regarding our affairs as is just and reasonable.

 

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Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. In addition, our general partner and its affiliates have the right to include such securities in a registration by us or any other unitholder, subject to customary exceptions. These registration rights continue for two years following any withdrawal or removal of our general partner. In addition, we are restricted from granting any superior piggyback registration rights during this two-year period. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts. In connection with any registration of this kind, we will indemnify the unitholders participating in the registration and their officers, directors and controlling persons from and against specified liabilities, including under the Securities Act or any applicable state securities laws. Please read “Units Eligible for Future Sale.”

 

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UNITS ELIGIBLE FOR FUTURE SALE

Memorial Resource holds an aggregate of 7,061,294 common units and 5,360,912 subordinated units as of the date of this prospectus. All of the subordinated units will convert into common units at the end of the subordination period. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 

  Ÿ  

1.0% of the total number of the securities outstanding; or

 

  Ÿ  

the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A unitholder who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell his common units under Rule 144 without regard to the rule’s public information requirements, volume limitations, manner of sale provisions and notice requirements.

Our partnership agreement does not restrict our ability to issue any partnership interests. Any issuance of additional common units or other equity interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, our common units then outstanding. Please read “The Partnership Agreement—Issuance of Additional Securities.”

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units or other partnership interests that they hold, which we refer to as registerable securities. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any registerable securities to require registration of such registerable securities and to include any such registerable securities in a registration by us of common units or other partnership interests, including common units or other partnership interests offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following the withdrawal or removal of our general partner. In connection with any registration of units held by our general partner or its affiliates, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts. Except as described below, our general partner and its affiliates may sell their common units or other partnership interests in private transactions at any time, subject to compliance with certain conditions and applicable laws.

We, our general partner and certain of its affiliates and the directors and executive officers of our general partner have agreed, subject to certain exceptions, not to sell any common units for a period of 60 days from the date of this prospectus. For a description of these lock-up provisions, please read “Underwriting.”

 

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MATERIAL TAX CONSEQUENCES

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Akin Gump Strauss Hauer & Feld LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended, or the Internal Revenue Code, existing and proposed Treasury regulations promulgated under the Internal Revenue Code, or the Treasury Regulations, and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Memorial Production Partners LP and our operating company.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts, or IRAs, real estate investment trusts, or REITs, or mutual funds. In addition, this discussion only comments to a limited extent on state, local and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

No ruling has been or will be requested from the Internal Revenue Service, or the IRS, regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Akin Gump Strauss Hauer & Feld LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in available cash for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Akin Gump Strauss Hauer & Feld LLP and are based on the accuracy of the representations made by us.

For the reasons described below, Akin Gump Strauss Hauer & Feld LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales”); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Common Units—Allocations Between Transferors and Transferees”); and (iii) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election”).

 

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Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, production, transportation, storage and processing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 2% of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Akin Gump Strauss Hauer & Feld LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of our operating company for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Akin Gump Strauss Hauer & Feld LLP on such matters. It is the opinion of Akin Gump Strauss Hauer & Feld LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and our operating company will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Akin Gump Strauss Hauer & Feld LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Akin Gump Strauss Hauer & Feld LLP relied include the following:

 

  Ÿ  

Neither we nor the operating company has elected or will elect to be treated as a corporation;

 

  Ÿ  

For each taxable year of our existence, more than 90% of our gross income has been and will be income that Akin Gump Strauss Hauer & Feld LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code; and

 

  Ÿ  

Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, natural gas, or products thereof that are held or to be held by us in activities that Akin Gump Strauss Hauer & Feld LLP has opined or will opine result in qualifying income.

We believe that these representations have been true in the past and expect that these representations will be true in the future.

 

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If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for federal income tax purposes.

If we were treated as an association taxable as a corporation for U.S. federal income tax purposes in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Akin Gump Strauss Hauer & Feld LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Memorial Production Partners LP will be treated as partners of Memorial Production Partners LP for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Memorial Production Partners LP for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales.”

Items of our income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their tax consequences of holding common units in Memorial Production Partners LP. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Memorial Production Partners LP for federal income tax purposes.

 

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Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections of Unitholder Taxes,” we will not pay any U.S. federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions made by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “—Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “—Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2015, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that earnings from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political

 

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uncertainties beyond our control. Further, the estimates are based on current federal income tax law and federal income tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

 

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gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units;

 

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we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering; or

 

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legislation is passed that would limit or repeal certain U.S. federal income tax preferences currently available to oil and gas exploration and production companies. Please read “—Tax Treatment of Operations—Recent Legislative Developments.”

Basis of Common Units

A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or a corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholders’ tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

 

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In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The at-risk limitation applies on an activity-by-activity basis, and in the case of oil and natural gas properties, each property is treated as a separate activity. Thus, a taxpayer’s interest in each oil or natural gas property is generally required to be treated separately so that a loss from any one property would be limited to the at-risk amount for that property and not the at-risk amount for all the taxpayer’s oil and natural gas properties. It is uncertain how this rule is implemented in the case of multiple oil and natural gas properties owned by a single entity treated as a partnership for federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or natural gas properties we own in computing a unitholder’s at-risk limitation with respect to us. If a unitholder were required to compute his at-risk amount separately with respect to each oil or natural gas property we own, he might not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at-risk amount with respect to his units as a whole.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

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interest on indebtedness properly allocable to property held for investment;

 

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our interest expense attributed to portfolio income; and

 

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the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

 

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The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders for purposes of the investment interest expense limitation. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections of Unitholder Taxes

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of an offering and (ii) any difference between the tax basis and fair market value of any property contributed to us by the general partner and its affiliates that exists at the time of such contribution, together, referred to in this discussion as the “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to the general partner and our other unitholders immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of

 

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ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

 

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his relative contributions to us;

 

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the interests of all the partners in profits and losses;

 

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the interest of all the partners in cash flow; and

 

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the rights of all the partners to distributions of capital upon liquidation.

Akin Gump Strauss Hauer & Feld LLP is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Common Units—Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for 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. As a result, during this period:

 

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any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

 

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any cash distributions received by the unitholder as to those units would be fully taxable; and

 

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all of these distributions may be subject to ordinary income tax.

Akin Gump Strauss Hauer & Feld LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common 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 and loaning their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “—Disposition of Common Units—Recognition of Gain or Loss.”

 

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Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

A 3.8% Medicare tax on certain investment income earned by individuals, estates and trusts will apply for taxable years beginning after December 31, 2012. For these purposes, investment income generally includes a unitholder’s allocable share of our income and any gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income from all investments or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filed separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. This election is irrevocable without the consent of the IRS unless there is a technical termination of the partnership. Please read “—Disposition of Common Units—Constructive Termination.” The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (i) his share of our tax basis in our assets (“common basis”) and (ii) his Section 743(b) adjustment to that basis.

We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property subject to depreciation under Section 168 of the Internal Revenue Code whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance

 

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method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “—Uniformity of Units.”

Although Akin Gump Strauss Hauer & Feld LLP is unable to opine as to the validity of this approach because there is no direct or indirect controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “—Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Common Units—Recognition of Gain or Loss.” The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the fair market value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to

 

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be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “—Disposition of Common Units—Allocations Between Transferors and Transferees.”

Depletion Deductions

Subject to the limitations on deductibility of losses discussed above (please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses”), unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our oil and natural gas interests. Although the Internal Revenue Code requires each unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for federal income tax purposes. Each unitholder, however, remains responsible for calculating his own depletion allowance and maintaining records of his share of the adjusted tax basis of the underlying property for depletion and other purposes.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative contracts or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder’s average net daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss

 

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carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.

Unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the unitholder’s share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder’s share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our oil and natural gas interests or the disposition by the unitholder of some or all of his units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each unitholder and not by our partnership, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. Moreover, the availability of percentage depletion may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “—Recent Legislative Developments.” We encourage each prospective unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Deductions for Intangible Drilling and Development Costs

We will elect to currently deduct intangible drilling and development costs (IDCs). IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies and other items that are incidental to, and necessary for, the drilling and preparation of wells for the production of oil, natural gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

Although we will elect to currently deduct IDCs, each unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount in respect of those IDCs will result for alternative minimum tax purposes.

Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to oil and natural gas wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An “integrated oil company” is a taxpayer that has economic interests in oil or natural gas properties and also carries on substantial retailing or refining operations. An oil or natural gas producer is deemed to be a

 

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substantial retailer or refiner if it is subject to the rules disqualifying retailers and refiners from taking percentage depletion. To qualify as an “independent producer” that is not subject to these IDC deduction limits, a unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 barrels of oil (or the equivalent amount of natural gas) on average for any day during the taxable year or in the retail marketing of oil and natural gas products exceeding $5 million per year in the aggregate.

IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the adjusted tax basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a unitholder of interests in us. Recapture is generally determined at the unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

The election to currently deduct IDCs may be restricted or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “—Recent Legislative Developments.”

Deduction for U.S. Production Activities

Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to 6% of our qualified production activities income that is allocated to such unitholder, but not to exceed 50% of such unitholder’s IRS Form W-2 wages for the taxable year allocable to domestic production gross receipts.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each unitholder will aggregate his share of the qualified production activities income allocated to him from us with the unitholder’s qualified production activities income from other sources. Each unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are taken into account only if and to the extent the unitholder’s share of losses and deductions from all of our activities is not disallowed by the tax basis rules, the at-risk rules or the passive activity loss rules. Please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses.”

The amount of a unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages

 

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that are deducted in arriving at qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders, and thus a unitholder’s ability to claim the Section 199 deduction may be limited.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 wages, or how such items are allocated by us to unitholders. Further, because the Section 199 deduction is required to be computed separately by each unitholder, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to the unitholders. Moreover, the availability of Section 199 deductions may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “—Recent Legislative Developments.” Each prospective unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.

Lease Acquisition Costs

The cost of acquiring oil and natural gas lease or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read “—Tax Treatment of Operations—Depletion Deductions.”

Geophysical Costs

The cost of geophysical exploration incurred in connection with the exploration and development of oil and natural gas properties in the United States are deducted ratably over a 24-month period beginning on the date that such expense is paid or incurred.

Operating and Administrative Costs

Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses that are reasonable in amount.

Recent Legislative Developments

Both President Obama’s budget proposal for the Fiscal Year 2013 and other recently introduced legislation recommended changes in federal income tax laws including the elimination of certain key U.S. federal income tax preferences relating to oil and natural gas exploration and development. Changes in the proposals 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 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, 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. In addition, the Obama Administration is considering, and, in the last Congressional session, the U.S. House of

 

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Representatives passed legislation that would have provided for substantive changes to the definition of qualifying income and the treatment of certain types of income earned from profits interests in partnerships. It is possible that these legislative efforts could result in changes to the existing federal income tax laws that affect publicly traded partnerships. As previously proposed, we do not believe any such legislation would affect our tax treatment as a partnership. However, the proposed legislation could be modified in a way that could affect us. 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 common units.

Initial Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our general partner, its affiliates and other unitholders, and (ii) any other offering will be borne by our general partner and other unitholders as of that time. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read “—Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Common Units—Recognition of Gain or Loss.”

The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

 

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Disposition of Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 15% through December 31, 2012 and 20% thereafter (absent new legislation extending or adjusting the current rate). However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

 

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Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

 

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a short sale;

 

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an offsetting notional principal contract; or

 

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a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, in the discretion of our general partner, gain or loss realized on a sale or other disposition of our assets or any other extraordinary items of income, gain, loss or deduction will be allocated among the unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although there is no direct or indirect controlling authority on the issue, we intend to use our proration method because simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions. Recently, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the safe harbor in the proposed regulations differs from the proration method we have adopted because the safe harbor would allocate tax items among the months based upon the relative number of days in each month, and could require certain tax items which our general partner may not consider extraordinary to be allocated to the month in which such items actually occur. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Akin Gump Strauss Hauer & Feld LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

 

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A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have technically terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. 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 result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders receiving two Schedules K-1 if the relief discussed below is unavailable) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or

 

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amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable methods and lives as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, distributions to non-U.S. unitholders are subject to withholding at the highest applicable effective tax rate. Each non-U.S. unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes

 

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in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the United States by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Akin Gump Strauss Hauer & Feld LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names Memorial Production Partners GP LLC, our general partner, as our Tax Matters Partner.

 

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The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

 

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the name, address and taxpayer identification number of the beneficial owner and the nominee;

 

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a statement regarding whether the beneficial owner is:

 

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a person that is not a U.S. person;

 

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a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

 

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a tax-exempt entity;

 

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the amount and description of units held, acquired or transferred for the beneficial owner; and

 

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specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is

 

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imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

 

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for which there is, or was, “substantial authority”; or

 

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as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts.

No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is not reasonable cause defense to the imposition of this penalty to such transactions.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of 6 successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “—Information Returns and Audit Procedures.”

 

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Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following:

 

  Ÿ  

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Accuracy-Related Penalties”;

 

  Ÿ  

for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

 

  Ÿ  

in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

State, Local and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We currently own property or do business in Louisiana and Texas. Upon consummation of the Beta acquisition, we will own property or do business in California. We may own property or do business in a number of jurisdictions in the future. Generally, each of the states in which we might do business, other than Texas, imposes a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity-Level Collections of Unitholder Taxes.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

The personal tax consequences of an investment in us may vary among unitholders under the laws of pertinent jurisdictions and, therefore, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal, tax returns that may be required of him. Akin Gump Strauss Hauer & Feld LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

 

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INVESTMENT IN MEMORIAL PRODUCTION PARTNERS LP BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA (collectively, “Similar Laws”). For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or individual retirement accounts or annuities (“IRAs”) established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements. Among other things, consideration should be given to:

 

  Ÿ  

whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

 

  Ÿ  

whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

 

  Ÿ  

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Tax Consequences—Tax-Exempt Organizations and Other Investors”; and

 

  Ÿ  

whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that, with respect to the plan, are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.

 

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The Department of Labor regulations provide guidance with respect to whether, in certain circumstances, the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets.” Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

 

  Ÿ  

the equity interests acquired by the employee benefit plan are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;

 

  Ÿ  

the entity is an “operating company,”—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

 

  Ÿ  

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

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in the first two bullet points above.

In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

 

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UNDERWRITING

Subject to the terms and conditions in an underwriting agreement dated                     , 2012, the underwriters named below, for whom Raymond James & Associates, Inc. is acting as representative, have severally agreed to purchase from us, and we have agreed to sell to them, the number of common units set forth opposite their names below:

 

Underwriter

   Number of
Common Units
 

Raymond James & Associates, Inc.

  

Citigroup Global Markets Inc.

  

Merrill Lynch, Pierce, Fenner & Smith

                             Incorporated

  

Barclays Capital Inc.

  

RBC Capital Markets, LLC

  

Wells Fargo Securities, LLC

  

Oppenheimer & Co. Inc.

  

Sanders Morris Harris Inc.

  

Wunderlich Securities, Inc.

  
  

 

 

 

Total

     10,500,000   
  

 

 

 

The underwriting agreement provides that the obligations of the underwriters to purchase and accept delivery of the common units offered by this prospectus are subject to the satisfaction of the conditions contained in the underwriting agreement, including:

 

  Ÿ  

the representations and warranties made by us to the underwriters are true;

 

  Ÿ  

there is no material adverse change in the financial market; and

 

  Ÿ  

we deliver customary closing documents and legal opinions to the underwriters.

The underwriters are obligated to purchase and accept delivery of all of the common units offered by this prospectus, if any are purchased, other than those covered by the option to purchase additional common units described below.

The underwriters propose to offer the common units directly to the public at the public offering price indicated on the cover page of this prospectus and to various dealers at that price less a concession not in excess of $         per unit. If all of the common units are not sold at the public offering price, the underwriters may change the public offering price and other selling terms. The common units are offered by the underwriters as stated in this prospectus, subject to receipt and acceptance by them. The underwriters reserve the right to reject an order for the purchase of the common units in whole or in part.

Option to Purchase Additional Common Units

We have granted the underwriters an option, exercisable for 30 days after the date of this prospectus, to purchase from time to time up to an aggregate of 1,575,000 additional common units to cover over-allotments, if any, at the public offering price less the underwriting discount set forth on the cover page of this prospectus. The underwriters may exercise the option to purchase additional common units only to cover over-allotments made in connection with the sale of the common units offered in this offering.

 

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Discounts and Expenses

The following table shows the amount per common unit and total underwriting discounts we will pay to the underwriters (dollars in thousands, except per unit amounts). The amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.

 

       Paid by Memorial Production Partners LP    
     No Exercise      Full Exercise  

Per common unit

   $                    $                

Total

   $         $     

In no event will the compensation to be paid to Financial Industry Regulatory Authority (“FINRA”) members in connection with this offering, including without limitation, underwriting discount and commissions, exceed 10% of the proceeds from the sale of the common units. The expenses of this offering that are payable by us are estimated to be $1.0 million.

Indemnification

We have agreed to indemnify the underwriters against certain liabilities that may arise in connection with this offering, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for those liabilities.

Lock-Up Agreements

We, our general partner, certain of our general partner’s officers and directors and certain of our affiliates have agreed with the underwriters, for a period of 60 days after the date of this prospectus, without the prior written consent of Raymond James & Associates, Inc.:

 

  Ÿ  

not to offer for sale, sell, pledge or otherwise dispose of or grant or sell any option or contract to purchase any common units (other than upon vesting of awards granted under the Memorial Production Partners, GP LLC Long-Term Incentive Plan or the issuance of restricted common units thereunder not to exceed 25,000 common units in the aggregate), except that we may issue common units or any securities convertible or exchangeable into the common units as payment of any part of the purchase price for businesses that we acquire; provided that any recipient of such common units must agree in writing to be bound by these provisions for the remainder of the lock-up period;

 

  Ÿ  

not to file or cause to be filed a registration statement, including any amendments, with respect to the registration of any common units or participate in any such registration, including under this registration statement (other than (i) any Rule 462(b) registration statement filed to register securities to be sold to the underwriters pursuant to the underwriting agreement, (ii) any registration statement on Form S-8 or amendment thereto to register common units or convertible or exchangeable into common units pursuant to the Memorial Production Partners GP LLC Long-Term Incentive Plan, (iii) any registration statement in connection with our entrance into a definitive agreement relating to an acquisition, or (iv) any registration statement on Form S-3);

 

  Ÿ  

not to enter into any swap or other agreement that transfers any of the economic consequences of ownership of any of the common units; and

 

  Ÿ  

not to enter into any hedging, collar or other transaction or arrangement that is designed or reasonably expected to lead to or result in a transfer, in whole or in part, of any of the economic consequences of ownership of the common units, whether or not such transfer would be for any consideration.

 

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Except as noted above, these agreements also prohibit us from entering into any of the foregoing transactions with respect to any securities that are convertible into or exchangeable for the common units or with respect to us, to publicly disclose the intention to do the foregoing transactions.

Raymond James & Associates, Inc. may, in its discretion and at any time without notice, release all or any portion of the securities subject to these agreements. Raymond James & Associates, Inc. does not have any present intent or any understanding to release all or any portion of the securities subject to these agreements.

The 60-day period described in the preceding paragraphs will be extended if:

 

  Ÿ  

during the last 17 days of the 60-day period, we issue a release concerning distributable cash or announce material news or a material event relating to us occurs; or

 

  Ÿ  

prior to the expiration of the 60-day period, we announce that we will release distributable cash results during the 16-day period beginning on the last day of the 60-day period, in which case the restrictions described in the preceding paragraphs will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release, the announcement of the material news or the occurrence of the material event.

Stabilization

Until this offering is completed, rules of the SEC may limit the ability of the underwriters to bid for and purchase the common units. As an exception to these rules, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of the common units, including:

 

  Ÿ  

short sales;

 

  Ÿ  

syndicate covering transactions;

 

  Ÿ  

imposition of penalty bids; and

 

  Ÿ  

purchases to cover positions created by short sales.

Stabilizing transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of the common units while this offering is in progress. Stabilizing transactions may include making short sales of common units, which involve the sale by the underwriters of a greater number of common units than they are required to purchase in this offering and purchasing common units from us or in the open market to cover positions created by short sales. Short sales may be “covered” shorts, which are short positions in an amount not greater than the underwriters’ option to purchase additional common units referred to above, or may be “naked” shorts, which are short positions in excess of that amount.

Each underwriter may close out any covered short position either by exercising its option to purchase additional common units, in whole or in part, or by purchasing common units in the open market. In making this determination, each underwriter will consider, among other things, the price of common units available for purchase in the open market compared to the price at which the underwriter may purchase common units pursuant to the option to purchase additional common units.

 

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A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market that could adversely affect investors who purchased in this offering. To the extent that the underwriters create a naked short position, they will purchase common units in the open market to cover the position.

As a result of these activities, the price of the common units may be higher than the price that otherwise might exist in the open market. If the underwriters commence these activities, they may discontinue them without notice at any time. The underwriters may carry out these transactions on the NYSE or otherwise.

Relationships

Affiliates of Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., RBC Capital Markets, LLC and Wells Fargo Securities, LLC are lenders under our revolving credit facility. In addition, an affiliate of Wells Fargo Securities, LLC is a lender under Rise Energy Operating, LLC’s credit facility, which we expect to be repaid in connection with the closing of the Beta acquisition.

The underwriters and their affiliates may provide in the future investment banking, financial advisory or other financial services for us and our affiliates, for which they may receive advisory or transaction fees, as applicable, plus out-of-pocket expenses, of the nature and in amounts customary in the industry for these financial services.

Listing

Our common units are listed on NASDAQ under the symbol “MEMP.”

Electronic Prospectus

A prospectus in electronic format may be available on the Internet sites or through other online services maintained by one or more of the underwriters participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the underwriters, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriters’ website and any information contained in any other website maintained by the underwriters is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been approved or endorsed by us or any underwriter in its capacity as underwriter and should not be relied upon by investors.

FINRA Rules

Because FINRA views the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with FINRA Rule 2310. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

 

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Notice to Prospective Investors in the European Economic Area

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

 

  Ÿ  

to any legal entity which is a qualified investor as defined in the Prospectus Directive;

 

  Ÿ  

to fewer than 100 or, if the Relevant Member State has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by the Issuer for any such offer; or

 

  Ÿ  

in any other circumstances falling within Article 3(2) of the Prospectus Directive;

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in the Relevant Member State, and includes any relevant implementing measure in each relevant member state. The expression 2010 PD Amending Directive means Directive 2010/73/EU.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

Notice to Prospective Investors in the United Kingdom

We may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000 (“FSMA”) that is not a “recognised collective investment scheme” for the purposes of FSMA (“CIS”) and that has not been authorised or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

(i) if we are a CIS and are marketed by a person who is an authorised person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) Order 2001, as amended (the “CIS Promotion Order”) or (b) high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or

 

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(ii) otherwise, if marketed by a person who is not an authorised person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the “Financial Promotion Order”) or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

(iii) in both cases (i) and (ii) to any other person to whom it may otherwise lawfully be made, (all such persons together being referred to as “relevant persons”). The common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this prospectus or any of its contents.

An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to us.

Notice to Prospective Investors in Germany

This prospectus has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute the common units in Germany. Consequently, the common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this prospectus and any other document relating to this offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of the common units to the public in Germany or any other means of public marketing. The common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This prospectus is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

This offering of our common units does not constitute an offer to buy or the solicitation or an offer to sell the common units in any circumstances in which such offer or solicitation is unlawful.

Notice to Prospective Investors in the Netherlands

The common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

Notice to Prospective Investors in Switzerland

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. The common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be distributed in connection with any such public offering.

 

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We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006 (“CISA”). Accordingly, the common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be made available through a public offering in or from Switzerland. The common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

 

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VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Akin Gump Strauss Hauer & Feld LLP, Houston, Texas. Certain legal matters in connection with the common units offered by us will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The consolidated and predecessor combined balance sheets of Memorial Production Partners LP as of December 31, 2011 and 2010, and the related consolidated and predecessor combined statements of operations, equity, and cash flows for each of the years in the three-year period ended December 31, 2011 have been incorporated by reference from our Current Report on Form 8-K filed November 20, 2012 in reliance upon the report of KPMG LLP, independent registered public accounting firm, incorporated by reference herein upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements of Rise Energy Operating, LLC as of December 31, 2011 and 2010 and for the period from February 3, 2009 (Inception) through December 31, 2011 and the statements of revenues and direct operating expenses of the Beta properties for the period January 1, 2009 to December 30, 2009 have been included herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

The statements of revenues and direct operating expenses of the oil and gas properties acquired by BlueStone Natural Resources Holdings, LLC from BP America Production Company for the three years in the period ended December 31, 2010 have been included herein in reliance upon the report of Ernst & Young LLP, independent auditors, appearing elsewhere herein, and upon the authority of said firm as experts in auditing and accounting.

The statements of operating revenues and direct operating expenses of the Carthage Properties that were acquired by WHT Energy Partners LLC for the years ended December 31, 2010, 2009 and 2008, included in this Prospectus have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report appearing herein (which report expresses an unqualified opinion and includes explanatory paragraphs referring to (1) the purpose of the statements; and (2) the adoption of oil and gas reserve estimation and disclosure rules effective December 31, 2009). Such statements of operating revenues and direct operating expenses of the Carthage Properties have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

Estimated quantities of our proved oil and natural gas reserves and the net present value of such reserves as of September 30, 2012 set forth in this prospectus are based upon reserve reports prepared by us and audited by Netherland, Sewell & Associates, Inc. Estimated quantities of our proved oil and natural gas reserves and the net present value of such reserves as of December 31, 2011 and December 31, 2010 set forth in this prospectus are based in part on reserve reports prepared by Netherland, Sewell & Associates, Inc. Estimated quantities of proved oil and natural gas reserves attributable to the Beta properties and the net present value of such reserves as of September 30, 2012, December 31, 2011 and December 31, 2010 set forth in this prospectus are based upon reserve reports prepared by Netherland, Sewell & Associates, Inc.

 

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WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and other reports with and furnish other information to the SEC. You may read and copy any document we file with or furnish to the SEC at the SEC’s public reference room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-732-0330 for further information on their public reference room. Our SEC filings are also available at the SEC’s website at http://www.sec.gov. Our website is located at http://www.memorialpp.com, and we make our periodic reports and other information filed with or furnished to 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 or the registration statement of which this prospectus forms a part. You may also request a copy of these filings at no cost, by writing or telephoning us at the following address: 1301 McKinney, Suite 2100, Houston, Texas 77010, (713) 588-8300.

The SEC allows us to “incorporate by reference” certain information we file with the SEC. This means we can disclose important information to you without actually including the specific information in this prospectus by referring to those documents. The information incorporated by reference is an important part of this prospectus. If information in incorporated documents conflicts with information in this prospectus, you should rely on the most recent information. If information in an incorporated document conflicts with information in another incorporated document, you should rely on the most recent incorporated document.

We incorporate by reference the documents listed below (excluding information deemed to be furnished and not filed with the SEC):

 

  Ÿ  

Annual Report on Form 10-K for the year ended December 31, 2011;

 

  Ÿ  

Quarterly Reports of Form 10-Q for the quarterly periods ended March 31, 2012, June 30, 2012 and September 30, 2012;

 

  Ÿ  

Current Reports on Form 8-K filed on January 10, 2012, March 9, 2012, April 3, 2012, April 18, 2012, May 2, 2012, May 14, 2012, June 1, 2012, August 9, 2012, September 19, 2012, October 1, 2012, November 20, 2012, November 20, 2012 and December 4, 2012; and

 

  Ÿ  

the description of our common units in our registration statement on Form 8-A (File No. 001-35364) filed on December 5, 2011, and any subsequent amendment thereto filed for the purpose of updating such description.

 

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FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

 

  Ÿ  

business strategies;

 

  Ÿ  

ability to replace the reserves we produce through drilling and property acquisitions;

 

  Ÿ  

drilling locations;

 

  Ÿ  

oil and natural gas reserves;

 

  Ÿ  

technology;

 

  Ÿ  

realized oil and natural gas prices;

 

  Ÿ  

production volumes;

 

  Ÿ  

lease operating expenses;

 

  Ÿ  

general and administrative expenses;

 

  Ÿ  

future operating results;

 

  Ÿ  

cash flows and liquidity;

 

  Ÿ  

availability of drilling and production equipment;

 

  Ÿ  

availability of oil field labor;

 

  Ÿ  

capital expenditures;

 

  Ÿ  

availability and terms of capital;

 

  Ÿ  

marketing of oil and natural gas;

 

  Ÿ  

expectations regarding general economic conditions;

 

  Ÿ  

competition in the oil and natural gas industry;

 

  Ÿ  

effectiveness of risk management activities;

 

  Ÿ  

environmental liabilities;

 

  Ÿ  

counterparty credit risk;

 

  Ÿ  

expectations regarding governmental regulation and taxation;

 

  Ÿ  

expectations regarding distributions and distribution rates;

 

  Ÿ  

expectations regarding developments in oil-producing and natural-gas producing countries; and

 

  Ÿ  

plans, objectives, expectations and intentions.

 

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These types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in “Summary,” “Risk Factors” and other sections of this prospectus and the documents incorporated by reference in this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations as expressed in prospectus including, but not limited to:

 

  Ÿ  

our ability to generate sufficient cash to pay the minimum quarterly distribution or any other amount on our common units;

 

  Ÿ  

our substantial future capital requirements, which may be subject to limited availability of financing;

 

  Ÿ  

the uncertainty inherent in estimating our reserves;

 

  Ÿ  

our need to make accretive acquisitions or substantial capital expenditures to maintain our declining asset base;

 

  Ÿ  

cash flows and liquidity;

 

  Ÿ  

potential shortages of drilling and production equipment;

 

  Ÿ  

potential difficulties in the marketing of, and volatility in the prices for, oil and natural gas;

 

  Ÿ  

uncertainties surrounding the success of our secondary and tertiary recovery efforts;

 

  Ÿ  

competition in the oil and natural gas industry;

 

  Ÿ  

general political and economic conditions, globally and in the jurisdictions in which we operate;

 

  Ÿ  

legislation and governmental regulations, including climate change legislation;

 

  Ÿ  

the risk that our hedging strategy may be ineffective or may reduce our income;

 

  Ÿ  

actions of third-party co-owners of interest in properties in which we also own an interest; and

 

  Ÿ  

risks related to potential acquisitions, including our ability to make acquisitions on favorable terms or to integrate acquired properties.

The forward-looking statements contained in this prospectus and the documents incorporated in this prospectus by reference are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about

 

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future events may prove to be inaccurate. Specifically, these statements include information in this prospectus regarding the Beta acquisition, including the impact of the acquisition on our financial results. All readers are cautioned that the forward-looking statements contained in this prospectus and the documents incorporated in this prospectus by reference are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events or circumstances described in any forward-looking statement will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in the “Risk Factors” section of this prospectus and elsewhere in this prospectus, including the documents incorporated by reference herein. Any forward-looking statement speaks only as of the date on which it is made. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

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INDEX TO FINANCIAL STATEMENTS

 

MEMORIAL PRODUCTION PARTNERS LP

  

Unaudited Pro Forma Condensed Combined Financial Statements:

  

Introduction

     F-2   

Unaudited Pro Forma Condensed Combined Balance Sheet as of September 30, 2012

     F-5   

Unaudited Pro Forma Condensed Combined Statement of Operations for the Year Ended December 31, 2011

     F-6   

Unaudited Pro Forma Condensed Combined Statement of Operations for the Nine Months Ended September 30, 2012

     F-7   

Notes to Unaudited Pro Forma Combined Financial Statements

     F-8   

BETA ACQUISITION

  

Historical Consolidated Financial Statements as of December 31, 2011 and 2010 and for the Period February 3, 2009 (Inception) through December 31, 2011:

  

Independent Auditors’ Report

     F-20   

Consolidated Balance Sheets

     F-21   

Consolidated Statements of Operations

     F-22   

Consolidated Statement of Owners’ Equity

     F-23   

Consolidated Statements of Cash Flows

     F-24   

Notes to Consolidated Financial Statements

     F-25   

Unaudited Historical Consolidated Financial Statements as of September 30, 2012 and for the Nine Months Ended September 30, 2012 and September 30, 2011:

  

Consolidated Balance Sheets

     F-44   

Consolidated Statements of Operations

     F-45   

Consolidated Statement of Owners’ Equity

     F-46   

Consolidated Statements of Cash Flows

     F-47   

Notes to Consolidated Financial Statements

     F-48   

Historical Statement of Revenues and Direct Operating Expenses for the period January 1, 2009 to December 30, 2009:

  

Independent Auditors’ Report

     F-60   

Statement of Revenues and Direct Operating Expenses

     F-61   

Notes to Statement of Revenues and Direct Operating Expenses

     F-62   

BP ACQUISITION FINANCIAL STATEMENTS

  

Historical Statements of Revenues and Direct Operating Expenses for each of the three years in the period ended December 31, 2010, and the three months ended March 31, 2011 and March 31, 2010 (unaudited):

  

Report of Independent Auditors

     F-66   

Statements of Revenues and Direct Operating Expenses

     F-67   

Notes to Statements of Revenues and Direct Operating Expenses

     F-68   

CARTHAGE PROPERTIES FINANCIAL STATEMENTS

  

Historical Statements of Revenues and Direct Operating Expenses for the years ended December 31, 2010, 2009 and 2008 and for the three months ended March 31, 2011 and March 31, 2010 (unaudited):

  

Report of Independent Auditors

     F-72   

Statements of Revenues and Direct Operating Expenses

     F-73   

Notes to Statements of Revenues and Direct Operating Expenses

     F-74   

 

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MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL INFORMATION

Introduction

The following unaudited pro forma condensed combined financial information as of September 30, 2012, for the year ended December 31, 2011 and for the nine months ended September 30, 2012 are based upon the historical audited and unaudited financial statements of Memorial Production Partners LP (“Partnership”), as adjusted for the “Beta Acquisition and Offering Related Transactions” and “Other Transactions” described in more detail below.

Beta Acquisition and Offering Related Transactions:

 

  Ÿ  

Beta Acquisition. The Partnership will complete its acquisition of all the outstanding equity interests in Rise Energy Operating, LLC (“Rise”) and its subsidiaries for approximately $271.0 million, including $3 million of working capital and other customary adjustments, simultaneously with the closing of this offering with an effective date of September 1, 2012. Rise’s assets primarily consist of a 51.75% working interest in three Pacific Outer Continental Shelf blocks covering the Beta Field, and are located in federal waters approximately eleven miles offshore the Port of Long Beach, California. Associated facilities include three conventional wellhead and production processing platforms, a 17.5-mile pipeline and an onshore tankage and metering facility. We refer to this transaction as the “Beta Acquisition.” Both the Partnership and Rise are under the common control of Natural Gas Partners (“NGP”). As such, the Beta Acquisition will be accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired from Rise will be recorded at historical cost.

 

  Ÿ  

Offering Related Transactions. The Partnership expects to fund the Beta Acquisition with net proceeds generated from a public equity offering and with borrowings under its revolving credit facility, consisting of the following: (i) issuance of 10,500,000 common units at an assumed offering price of $18.25 per unit generating net proceeds of $183.1 million after deducting underwriting discounts and other offering related fees; and (ii) borrowings of $87.9 million, net of $0.3 million of deferred financing costs under its revolving credit facility.

Other Transactions:

The pro forma financial statements reflect those transactions which occurred subsequent to January 1, 2011 as follows:

 

  Ÿ  

The Partnership and/or our predecessor acquired interests in certain oil and natural gas properties in the following separate transactions subsequent to January 1, 2011:

2011 Third Party Acquisitions:

  Ÿ  

In April 2011, our predecessor acquired certain oil and natural gas properties located in East Texas from a third party, which are referred to as the “Carthage Properties”;

 

  Ÿ  

In May 2011, our predecessor acquired certain oil and natural gas properties located in South Texas from BP America Production Company, which are referred to as the “BP Properties”;

2012 Third Party Acquisitions:

  Ÿ  

In May 2012, the Partnership acquired certain oil and natural gas properties located in East Texas and North Louisiana from a third party; and

 

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  Ÿ  

In September 2012, the Partnership acquired certain oil and natural gas properties located in East Texas from a third party.

 

  Ÿ  

Predecessor Retained Operations. The results of our predecessor prior to our initial public offering (“IPO”) in December 2011 include the results of operations related to certain oil and natural gas assets that were not sold or contributed to the Partnership at the closing of our IPO. The accompanying unaudited pro forma condensed combined statement of operations for the year ended December 31, 2011 reflects certain adjustments to remove the impacts related to these operations, as further described in the accompanying notes.

 

  Ÿ  

2011 Memorial Production Partners LP IPO. On December 14, 2011, we completed our initial public offering of 9,000,000 common units at a price of $19.00 per unit, which generated net proceeds of approximately $146.5 million after deducting underwriting discounts, structuring fees and other offering and formation-related fees. We distributed approximately $73.6 million in cash, 7,061,294 common units and 5,360,912 subordinated units to Memorial Resource to acquire the net assets of our predecessor and repaid $198.3 million of our predecessor’s credit facilities concurrent with the closing of our IPO. The cash portion of this consideration was financed with $130.0 million in borrowings under our revolving credit facility and the net cash proceeds generated from our IPO. On December 22, 2011, the underwriters exercised a portion of their over-allotment option, purchasing an additional 600,000 common units, which generated net proceeds to the Partnership of approximately $10.7 million. Of this amount, $10.0 million was used to repay indebtedness under our revolving credit facility. For purposes of the pro forma statements of operations, these IPO related transactions were assumed to have occurred on January 1, 2011 as further explained in the accompanying unaudited pro forma condensed combined statement of operations for the year ended December 31, 2011 and related footnotes.

The unaudited pro forma condensed combined balance sheet is based on the unaudited historical consolidated balance sheet of the Partnership as of September 30, 2012 and includes pro forma adjustments to give effect to the Beta Acquisition and Offering Related Transactions as if they had occurred on September 30, 2012.

The unaudited pro forma condensed combined statement of operations are based on (i) the unaudited statement of operations of the Partnership for the nine months ended September 30, 2012 and the audited historical combined statement of operations of the Partnership and predecessor for the year ended December 31, 2011, each period having been adjusted to give effect to the Beta Acquisition, Offering Related Transactions, and Other Transactions as if they occurred on January 1, 2011, (ii) the historical statements of revenues and direct operating expenses of the BP Properties and the Carthage Properties in 2011, included elsewhere in this prospectus, and (iii) the historical accounting records of the sellers for the 2012 Third Party Acquisitions prior to the closing dates of the respective individually insignificant acquisitions.

The pro forma adjustments to the unaudited and audited historical combined financial statements are based on currently available information and certain estimates and assumptions. The actual effect of the transactions discussed in the accompanying notes ultimately may differ from the unaudited pro forma adjustments included herein. However, management believes that the assumptions utilized to prepare the pro forma adjustments provide a reasonable basis for presenting the significant effects of the transactions as currently contemplated and that the unaudited pro forma adjustments are factually supportable, give appropriate effect to the expected impact of events that are directly attributable to the transactions, and reflect those items expected to have a continuing impact on the Partnership.

 

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The unaudited pro forma combined financial statements of the Partnership are not necessarily indicative of the results that actually would have occurred if the Partnership had completed the Beta Acquisition, Offering Related Transactions or Other Transactions on the dates indicated or which could be achieved in the future because they necessarily exclude various operating expenses.

 

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MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET

SEPTEMBER 30, 2012

(in thousands)

 

    Partnership
Historical
    Distribution
Adjustment
        Partnership
Historical
As Adjusted
    Rise
Historical  As
Adjusted (b)
    Offering
Related
Adjustments
        Partnership
Pro Forma
Combined
 

ASSETS

               

Current assets:

               

Cash and cash equivalents

  $ 1,038               $ 1,038      $ 6,100      $ 88,168      (c)   $ 7,138   
              191,817      (d)  
              (241,000   (e)  
              (30,000   (e)  
              (8,985   (f)  

Accounts receivable:

               

Oil and natural gas sales

    9,810                 9,810        13,916            23,726   

Joint interest owners and other

    4,342                 4,342        2,928            7,270   

Affiliates

    1,798                 1,798        75            1,873   

Short-term derivative instruments

    15,942                 15,942        730            16,672   

Prepaid expenses and other current assets

    1,713                 1,713        1,585            3,298   
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

 

 

 

Total current assets

    34,643                 34,643        25,334                 59,977   

Property and equipment, at cost:

               

Oil and natural gas properties

    704,590                 704,590        120,121            824,711   

Other

    323                 323        656            979   

Accumulated depreciation, depletion and impairment

    (135,159              (135,159     (14,912         (150,071
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

 

 

 

Oil and natural gas properties, net

    569,754                 569,754        105,865                 675,619   

Long-term derivative instruments

    5,586                 5,586        456            6,042   

Restricted investments

                           67,100            67,100   

Other long-term assets

    2,016                 2,016        328        320      (f)     2,336   
              (328   (f)  
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

 

 

 

Total assets

  $ 611,999               $ 611,999      $ 199,083      $ (8   (f)   $ 811,074   
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

 

 

 

LIABILITIES AND EQUITY

               

Current liabilities:

               

Accounts payable

  $ 529                 529      $ 6,201      $        $ 6,730   

Accounts payable—affiliates

    901                 901                   901   

Revenues payable

    3,013                 3,013                   3,013   

Accrued liabilities

    8,262                 8,262        10,406            18,668   

Distribution Payable

           241,000      (a)     241,000               (241,000   (e)       

Short-term derivative instruments

    1,422                 1,422                   1,422   
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

 

 

 

Total current liabilities

    14,127        241,000          255,127        16,607        (241,000       30,734   

Long-term debt

    293,000                 293,000        30,000        88,168      (c)     381,168   
              (30,000   (e)  

Asset retirement obligations

    15,439                 15,439        58,266            73,705   

Long-term derivative instruments

    7,413                 7,413                   7,413   

Deferred tax liability

                           1,688            1,688   

Other long-term liabilities

    705                 705                   705   
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

 

 

 

Total liabilities

    330,684        241,000          571,684        106,561        (182,832       495,413   

Equity:

               

Limited partners:

               

Common units; 16,946,903 units outstanding (historical) and 27,446,903 outstanding (pro forma)

    223,675        (182,902   (a)     40,773               191,625      (d)     289,696   
               
              (8,993   (f)  
              66,291      (g)  

Subordinated units; 5,360,912 units outstanding (historical and pro forma)

    57,242        (57,857   (a)     (615            20,970      (g)     20,355   

General partner 22,330 units outstanding (historical) and 32,840 outstanding (pro forma)

    398        (241   (a)     157               192      (d)     436   
              87      (g)  

Members

            87,348        (87,348   (g)       

Non-controlling interest

                           5,174                 5,174   
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

 

 

 

Total equity

    281,315        (241,000       40,315        92,522        182,824          315,661   
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

 

 

 

Total liabilities and equity

  $ 611,999               $ 611,999      $ 199,083      $ (8     $ 811,074   
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

 

 

 

The accompanying notes are an integral part of this unaudited pro forma financial information.

 

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MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENTS OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2011

(in thousands, except per unit amounts)

 

    Partnership
Historical
    Rise
Historical  As
Adjusted (h)
    2011 Third  Party
Acquisition
Adjustments (i)
    2012 Third  Party
Acquisition
Adjustments (j)
    Predecessor
Retained(k)
    IPO and
Offering/
Financing
Related
Adjustments
        Partnership
Pro Forma
Combined
 

Revenues:

               

Oil & natural gas sales

  $ 84,058      $ 60,744      $ 12,758      $ 38,193      $ (1,701   $        $ 194,052   

Pipeline tariff income

           1,378                                      1,378   

Other income

    825        1,439                      (10              2,254   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

 

Total revenues

    84,883        63,561        12,758        38,193        (1,711              197,684   

Costs and expenses:

               

Lease and pipeline operating

    24,474        20,019        2,501        4,343        (1,593              49,744   

Exploration

    56        276               4        (56              280   

Production and ad valorem taxes

    4,790               1,507        2,243        91                 8,631   

Depreciation, depletion, and amortization

    30,052        5,191        4,540        9,608        (1,164              48,227   

Impairment of proved oil and natural gas properties

    15,141                             (4,046              11,095   

General and administrative

    10,399        4,186                      (217              14,368   

Accretion of asset retirement obligations

    1,069        2,348        91        39        (49              3,498   

Realized (gain) loss on commodity derivative instruments

    (7,944     1,163                                      (6,781

Unrealized (gain) loss on commodity derivative instruments

    (25,381     (2,605                                   (27,986

Gain on sale of properties

    (63,024                          744                 (62,280

Other, net

    1,908        116                                      2,024   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

 

Total costs and expenses

    (8,460     30,694        8,639        16,237        (6,290              40,820   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

 

Operating income

    93,343        32,867        4,119        21,956        4,579                 156,864   

Other income (expense):

               

Interest income

           1,137                                      1,137   

Amortization of investment premium

           (606                                   (606

Interest (expense) income, net

    (7,268     (884                   230        7,674      (l)     (11,828
              (2,478   (m)  
              (8,627   (n)  
              (475   (p)  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

 

Total other income (expense)

    (7,268     (353                   230        (3,906       (11,297
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

 

Income before income taxes

    86,075        32,514        4,119        21,956        4,809        (3,906       145,567   

Income tax benefit (expense)

    (122     65                                 (57
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

 

Net income

  $ 85,953      $ 32,579      $ 4,119      $ 21,956      $ 4,809      $ (3,906     $ 145,510   

Net income (loss) attributable to noncontrolling interest

           (146                                   (146
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

 

Net income attributable to partners and predecessor (Note 3)

  $ 85,953      $ 32,725      $ 4,119      $ 21,956      $ 4,809      $ (3,906     $ 145,656   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

 

 

 

Allocation of historical and pro forma net income (Note 3):

               

Limited partners

  $ 6,585                  $ 145,510   

General partner

  $ 7                  $ 146   

Earnings per unit:

               

Basic and diluted earnings per unit

  $ 0.30                  $ 4.51   

Weighted average limited partner units outstanding:

               

Basic and diluted

    21,756                    32,256   

The accompanying notes are an integral part of this unaudited pro forma financial information.

 

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MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENTS OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2012

(in thousands, except per unit amounts)

 

    Partnership
Historical
    Rise
Historical  As
Adjusted (h)
    2012 Third
Party

Acquisition
Adjustments (j)
    IPO and
Offering/
Financing
Related
Adjustments
        Partnership
Pro Forma
Combined
 

Revenues:

           

Oil & natural gas sales

  $ 54,725      $ 45,033      $ 21,013      $        $ 120,771   

Pipeline tariff income

           1,076                        1,076   

Other income

    163        217                        380   
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

 

Total revenues

    54,888        46,326        21,013                 122,227   

Costs and expenses:

           

Lease and pipeline operating

    19,118        15,467        2,455                 37,040   

Exploration

    414               1                 415   

Production and ad valorem taxes

    5,215               1,273                 6,488   

Depreciation, depletion, and amortization

    23,548        4,055        6,518                 34,121   

Impairment of proved oil and natural gas properties

                                    

General and administrative

    6,820        3,156                        9,976   

Accretion of asset retirement obligations

    840        1,837        19                 2,696   

Realized (gain) loss on commodity derivative instruments

    (24,606     661                        (23,945

Unrealized (gain) loss on commodity derivative instruments

    18,984        (1,953                     17,031   

Gain on sale of properties

    (192                            (192

Other, net

    468                               468   
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

 

Total costs and expenses

    50,609        23,223        10,266                 84,098   
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

 

Operating income

    4,279        23,103        10,747                 38,129   

Other income (expense):

           

Interest income

           514                        514   

Amortization of investment premium

           (170                     (170

Interest expense

    (7,943     (1,029            1,029      (o)     (12,785
          (1,845   (m)  
          (2,997   (n)  
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

 

Total other income (expense)

    (7,943     (685            (3,813       (12,441
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

 

Income (loss) before income taxes

    (3,664     22,418        10,747        (3,813       25,688   

Income tax benefit (expense)

    (26                            (26
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

 

Net income (loss)

  $ (3,690   $ 22,418      $ 10,747      $ (3,813     $ 25,662   

Net income (loss) attributable to noncontrolling interest

           17                        17   
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

 

Net income (loss) attributable to partners and predecessor (Note 3)

  $ (3,690   $ 22,401      $ 10,747      $ (3,813     $ 25,645   
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

 

Allocation of historical and pro forma net income (loss) (Note 3):

           

Limited partners

  $ (4,686           $ 25,619   

General partner

  $ (5           $ 26   

Earnings per unit:

           

Basic and diluted (loss) earnings per unit

  $ (0.21           $ 0.78   

Weighted average limited partner units outstanding:

           

Basic and diluted

    22,241                32,741   

The accompanying notes are an integral part of this unaudited pro forma financial information.

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

Note 1. Basis of Presentation

The unaudited pro forma condensed combined balance sheet of the Partnership as of September 30, 2012 is based on the unaudited historical consolidated balance sheet of the Partnership as of September 30, 2012 and includes pro forma adjustments to give effect to the Beta Acquisition and Offering Related Transactions as if they had occurred on September 30, 2012.

The unaudited pro forma condensed combined statement of operations of the Partnership are based on the unaudited statement of operations of the Partnership for the nine months ended September 30, 2012 and the audited historical combined statement of operations of the Partnership and our predecessor for the year ended December 31, 2011, each period having been adjusted to give effect to the Beta Acquisition, Offering Related Transactions and Other Transactions as if they occurred on January 1, 2011.

The Partnership believes that the assumptions used in the preparation of these unaudited pro forma condensed combined financial statements provide a reasonable basis for presenting the effects directly attributable to the transactions described above. These unaudited pro forma condensed combined financial statements and the notes thereto should be read in conjunction with:

 

  Ÿ  

the Partnership’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2012, which is incorporated by reference herein;

 

  Ÿ  

the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 10-K”), which is incorporated by reference herein;

 

  Ÿ  

the Partnership’s Current Report on Form 8-K filed with the SEC on November 20, 2012, which is incorporated by reference herein, that retrospectively revised certain financial and other information included in the 2011 10-K to give effect to the Partnership’s April and May 2012 acquisitions of oil and gas properties from entities under common control;

 

  Ÿ  

Rise’s audited historical financial statements and related notes as of December 31, 2011 and 2010 and for the period February 3, 2009 (inception) through December 31, 2011 included elsewhere in this prospectus; and

 

  Ÿ  

Rise’s unaudited historical financial statements and related notes as of September 30, 2012 and for the nine months ended September 30, 2012 and 2011 included elsewhere in this prospectus.

 

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Table of Contents

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

 

Note 2. Pro Forma Adjustments and Assumptions

Unaudited pro forma combined balance sheet

 

(a) Pro forma adjustment to reflect the distribution accrual related to the estimated $241.0 million cash distribution expected to be made to Rise upon closing of this offering. This distribution represents a portion of the consideration to be paid to Rise related to the assets included in the Beta Acquisition. This $241.0 million cash distribution will be funded with the net proceeds received in connection with this offering and borrowings under our revolving credit facility.

Upon closing, the Beta Acquisition will be accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired will be recorded at Rise’s historical carrying value.

 

(b) Pro forma adjustments to convert the historical Rise financial statements from the full cost method of accounting to the successful efforts method of accounting, as summarized below:

 

     Rise
Historical
     Rise
Pro Forma
Adjustments
    Rise
As
Adjusted
 
     (in thousands)  

ASSETS

       

Property and equipment, at cost:

       

Oil and natural gas properties

   $ 120,518       $ (397 )(1)    $ 120,121   

Other

     656                656   

Accumulated depreciation, depletion and impairment

     (20,369      18,651  (2)      (14,912
        (13,194 )(3)   
  

 

 

    

 

 

   

 

 

 

Oil and natural gas properties, net

   $ 100,805       $ 5,060      $ 105,865   
  

 

 

    

 

 

   

 

 

 

EQUITY

       

Members

     82,288         (397 )(1)      87,348   
        18,651  (2)   
        (13,194 )(3)   

 

(1) To reclassify to exploration expense geological and geophysical costs attributable to the development of oil and natural gas properties that was previously capitalized by Rise . The Partnership follows the successful efforts method of accounting for oil and natural gas properties while Rise follows the full cost method of accounting for oil and natural gas properties. Certain costs that are capitalized under the full cost method are expensed under the successful efforts method (e.g., geological and geophysical costs directly related to exploration and development activities).
(2) Cumulative pro forma adjustment to reverse accumulated depletion recorded by Rise under the full cost method of accounting. Under the successful efforts method of accounting, proved property acquisition costs are depleted on a unit-of-production basis over total proved reserves and costs of wells, related equipment and facilities are depleted over the life of the proved developed reserves that will utilize those capitalized assets on a field-by-field basis. Under the full cost method of accounting, property acquisition costs, costs of wells, related equipment and facilities and future development costs are included in a single full cost pool, which is depleted on a unit-of-production basis over total proved reserves.
(3) Cumulative pro forma adjustment to record accumulated depletion under the successful efforts method of accounting.

 

(c) Pro forma adjustment to reflect the cash proceeds related to borrowings by the Partnership of $88.2 million, which includes $0.3 million of deferred financing costs, under its revolving credit facility.

 

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Table of Contents

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

 

(d) Pro forma adjustments to reflect the gross cash proceeds of approximately $191.6 million from the issuance and sale of 10,500,000 common units at an assumed offering price of $18.25 per unit and $0.2 million from the contribution by our General Partner to maintain its 0.1% interest.

 

(e) Pro forma adjustments to record the use of the $271.0 million of net proceeds from this offering and borrowings under our revolving credit facility, all of which will be paid to Rise as consideration for the assets acquired in the Beta Acquisition, shown as follows:

 

  (1) To reflect the use by Rise of $30.0 million in proceeds to repay indebtedness under Rise’s existing credit facility; and

 

  (2) To reflect a $241.0 million cash distribution made to Rise for the remaining purchase price of the Beta Acquisition.

For further discussion on the application of the net proceeds from the Offering, please read “Use of Proceeds” in the forepart of this prospectus.

 

(f) Pro forma adjustment to reflect estimated deferred financing costs of $0.3 million related to additional borrowings under our revolving credit facility, underwriting discounts of $7.7 million, estimated offering expenses of $1.0 million and the write-off of $0.3 million of unamortized deferred financing costs upon repayment of Rise’s debt.

 

(g) To record the net book value of net assets transferred from Rise. Both the Partnership and Rise are under common control of NGP. As such, the Beta Acquisition will be accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired from Rise will be recorded at historical cost.

 

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Table of Contents

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

 

Unaudited pro forma statements of operations

 

(h) The pro forma adjustments detailed in the tables below convert the historical Rise financial statements from the full cost method of accounting to the successful efforts method of accounting and includes other certain reclassifications between the presentation within the Rise historical financial statements, included elsewhere in this prospectus, to our presentation.

 

For The Year Ended December 31, 2011  
      Rise Historical     Rise
Pro Forma
Adjustments
          Rise
As Adjusted
 
     (in thousands)  

Revenues:

        

Oil & natural gas sales

   $ 60,744      $ —          $ 60,744   

Pipeline tariff income

     1,378        —            1,378   

Other income

     1,439        —            1,439   
  

 

 

   

 

 

     

 

 

 

Total revenues

     63,561        —            63,561   

Cost and expenses:

        

Lease operating expenses

     20,019        —            20,019   

Exploration

     —          276        (1     276   

Production and ad valorem taxes

     —          —            —     

Depreciation, depletion, and amortization

     7,045        (6,548     (2     5,191   
       4,694        (3  

Impairment of proved oil and natural gas properties

     —          —            —     

General and administrative

     4,186        —            4,186   

Accretion of asset retirement obligations

     2,348        —            2,348   

Realized (gain) loss on commodity derivative instruments

     —          1,163        (4     1,163   

Unrealized (gain) loss on commodity derivative instruments

     —          (2,605     (4     (2,605

Gain on sale of properties

     —          —            —     

Management fee

     116        (116     (4     —     

Other, net

     —          116        (4     116   
  

 

 

   

 

 

     

 

 

 

Total costs and expenses

     33,714        (3,020       30,694   
  

 

 

   

 

 

     

 

 

 

Operating income

     29,847        3,020          32,867   

Other income (expense):

        

Unrealized gain (loss) on commodity derivatives

     2,605        (2,605     (4     —     

Realized loss on commodity derivatives

     (1,163     1,163        (4     —     

Interest income

     1,137        —            1,137   

Amortization of investment premium

     (606     —            (606

Interest expense

     (856     (28     (4     (884

Other

     (28     28        (4     —     
  

 

 

   

 

 

     

 

 

 

Total other income (expense)

     1,089        (1,442       (353
  

 

 

   

 

 

     

 

 

 

Income before income taxes

     30,936        1,578          32,514   

Income tax benefit (expense)

     65        —            65   
  

 

 

   

 

 

     

 

 

 

Net income

   $ 31,001      $ 1,578        $ 32,579   
  

 

 

   

 

 

     

 

 

 

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

 

Nine Months Ended September 30, 2012  
     Rise
Historical
    Rise
Pro Forma
Adjustments
          Rise
As Adjusted
 
     (in thousands)  

Revenues:

        

Oil & natural gas sales

   $ 45,033      $        $ 45,033   

Pipeline tariff income

     1,076                 1,076   

Other income

     217                 217   
  

 

 

   

 

 

     

 

 

 

Total revenues

     46,326                 46,326   

Cost and expenses:

        

Lease operating expenses

     15,467                 15,467   

Exploration

                       

Production and ad valorem taxes

                       

Depreciation, depletion, and amortization

     5,213        (4,737     (2     4,055   
       3,579        (3  

Impairment of proved oil and natural gas properties

                       

General and administrative

     3,156                 3,156   

Accretion of asset retirement obligations

     1,837                 1,837   

Realized (gain) loss on commodity derivative instruments

            661        (4     661   

Unrealized (gain) loss on commodity derivative instruments

            (1,953     (4     (1,953

Gain on sale of properties

                       

Management Fee

                       

Other, net

                       
  

 

 

   

 

 

     

 

 

 

Total costs and expenses

     25,673        (2,450       23,223   
  

 

 

   

 

 

     

 

 

 

Operating income

     20,653        2,450          23,103   

Other income (expense):

        

Unrealized gain (loss) on commodity derivaties

     1,953        (1,953     (4       

Realized loss on commodity derivatives

     (661     661        (4       

Interest income

     514                 514   

Amortization of investment premium

     (170              (170

Interest expense

     (993     (36     (4     (1,029

Other

     (36     36        (4       
  

 

 

   

 

 

     

 

 

 

Total other income (expense

     607        (1,292       (685

Income before income taxes

     21,260        1,158          22,418   

Income tax benefit (expense)

                       
  

 

 

   

 

 

     

 

 

 

Net Income

     $21,260      $ 1,158          $22,418   
  

 

 

   

 

 

     

 

 

 

 

(1) To record expense related to geological and geophysical costs attributable to the development of oil and natural gas properties that was previously capitalized by Rise. The Partnership follows the successful efforts method of accounting for oil and natural gas properties while Rise follows the full cost method of accounting for oil and natural gas properties. Certain costs that are capitalized under the full cost method are expensed under the successful efforts method (e.g., geological and geophysical costs directly related to exploration and development activities).

 

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Table of Contents

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

 

(2) Pro forma adjustment to reverse depletion under the full cost method of accounting recorded by Rise. Under the successful efforts method of accounting, proved property acquisition costs are depleted on a unit-of-production basis over total proved reserves and costs of wells, related equipment and facilities are depreciated over the life of the proved developed reserves that will utilize those capitalized assets on a field-by-field basis. Under the full cost method of accounting, property acquisition costs, costs of wells, related equipment and facilities and future development costs are included in a single full cost pool, which is depleted on a unit-of-production basis over total proved reserves.
(3) Pro forma adjustment to record depletion under the successful efforts method of accounting
(4) Adjustments to reclass certain items from the presentation within the Rise historical financial statements for the year ended December 31, 2011 and nine months ended September 30, 2012, included elsewhere in this prospectus to conform to our presentation.

 

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Table of Contents

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

 

(i) The adjustments below reflect the pro forma revenues and expenses associated with the 2011 Third Party Acquisitions. The statements of revenues and direct operating expenses for the BP Properties and Carthage Properties are included elsewhere in this prospectus.

 

Year Ended December 31, 2011  
      Carthage
Properties
Revenues &
Direct
Operating
Expenses
     BP
Properties
Revenues &
Direct
Operating
Expenses
     Additional
Adjustments
for
Property
Acquisitions
          Partnership
Properties
Adjustments
 
     (1)      (2)                     
     (In thousands)  

Revenues:

            

Oil & natural gas sales

   $ 15,069       $ 3,732       $ (8,563     (3   $ 12,758   
           (798     (6  
           483        (7  
           2,835        (8  

Other income

                                
  

 

 

    

 

 

    

 

 

     

 

 

 

Total revenues

     15,069         3,732         (6,043       12,758   

Costs and expenses:

            

Lease operating

     2,124         993         (1,275     (3     2,501   
          
65
  
 

 

(7

 
           594        (8  

Transportation

     798                 (798     (6       

Exploration

                                

Production taxes

     1,142         579         (685     (3     1,507   
           41        (7  
           430        (8  

Depreciation, depletion and amortization

                     1,361        (4     4,540   
           3,179        (5  

Impairment of proved oil and natural gas properties

                                

General and administrative

                                

Accretion

                     65        (4     91   
                     26        (5       

(Gain)/loss on derivative instruments

                                

Gain on sale of properties

                                

Other, net

                                
  

 

 

    

 

 

    

 

 

     

 

 

 

Total costs and expenses

     4,064         1,572         3,003          8,639   
  

 

 

    

 

 

    

 

 

     

 

 

 

Operating (loss) income

     11,005         2,160         (9,046       4,119   

Interest expense

                                
  

 

 

    

 

 

    

 

 

     

 

 

 

Net (loss) income

   $ 11,005       $ 2,160       $ (9,046     $ 4,119   
  

 

 

    

 

 

    

 

 

     

 

 

 

 

(1)

Adjustments reflect the actual historical revenues and direct operating expenses of the properties acquired by WHT Energy Partners LLC (“WHT”) on April 8, 2011, as noted above, for the three month period ended March 31, 2011. Historical lease operating statements by

 

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Table of Contents

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

 

  individual asset were used as the basis for the revenues and direct operating expenses. See footnote (7) for discussion related to the Carthage Properties pro forma and actual historical results subsequent to March 31, 2011.

 

(2) Adjustments reflect the actual historical revenues and direct operating expenses of the BP Properties acquired by our predecessor on May 31, 2011, as noted above, for the three month period ended March 31, 2011. Historical lease operating statements by individual asset were used as the basis for the revenues and direct operating expenses. See footnote (8) for discussion related to the BP Properties pro forma and actual historical results subsequent to March 31, 2011.

 

(3) Pro forma adjustments to reflect the 60% of the revenues and direct operating expenses associated with the properties acquired by WHT on April 8, 2011 that were not sold and contributed to the Partnership in the IPO. These adjustments are net of the reclassification described in footnote (6) below.

 

(4) Pro forma adjustment to reflect the depletion and depreciation on property and equipment and the accretion expense on asset retirement obligations prior to the closing date of April 8, 2011 associated with the Carthage Properties. The adjustments reflect the Partnership’s 40% share of the properties acquired by WHT on April 8, 2011.

 

(5) Pro forma adjustments to reflect the depletion and depreciation on property and equipment and the accretion expense on asset retirement obligations prior to the closing date of May 31, 2011 associated with the BP Properties acquired by our predecessor.

 

(6) Amounts represent historical transportation and marketing costs related to the Carthage Properties for the three months ended March 31, 2011. The seller of the Carthage Properties previously recorded these amounts within expenses, as it paid such amounts on a gross basis to a third-party transportation and marketing company. However, WHT receives a wellhead price from the third-party purchasers that is net of transportation and marketing costs, and expenses associated with the properties acquired by WHT on April 8, 2011 have been reclassified from expenses to within revenue on the pro forma combined statements of operations to reflect the Partnership’s net presentation of such costs subsequent to the acquisition of the Carthage Properties but prior to the adjustments shown in footnote (3) above. Finally, the pro forma adjustments for the period subsequent to March 31, 2011 until the closing date of April 8, 2011 were calculated net of transportation and marketing costs.

 

(7) Pro forma adjustments to reflect the revenues, lease operating expenses and production taxes associated with the Partnership’s 40% interest in the Carthage Properties acquired by WHT for the period subsequent to March 31, 2011 until the closing date of April 8, 2011. The Carthage Properties actual results subsequent to the closing date of their acquisition are included in our predecessor’s statement of operations.

 

(8) Pro forma adjustments to reflect the revenues, lease operating expenses and production taxes associated with the BP Properties acquired by our predecessor for the period subsequent to March 31, 2011 until the closing date of May 31, 2011. The BP Properties’ actual results subsequent to the closing date of their respective acquisition are included in our predecessor’s statement of operations.

 

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Table of Contents

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

 

(j) Pro forma adjustments associated with the revenues and direct operating expenses for the individually insignificant 2012 Third Party Acquisitions, depletion expense applied to the adjusted basis of the properties acquired and accretion expense. Historical lease operating statements provided by the sellers were used as the basis for determining pro forma adjustments.

 

(k) Adjustments to remove the revenues and expenses related to certain oil and natural gas assets that were included in our predecessor’s results of operations prior to the closing of our IPO on December 14, 2011 but were not sold or contributed to us at the closing of our IPO. The adjustment applied to the historical basis of each account was based on either specific identification or an allocation by percentage of the relative fair value of the oil and natural gas properties retained. General and administrative expenses are allocated based on the well count for the properties retained by our predecessor.

 

(l) Pro forma adjustment of $7.7 million for the year ended December 31, 2011 to reflect the reduction in historical interest expense associated with our predecessor’s debt that was repaid in connection with our IPO in December 2011 and Rise’s debt that will be repaid in connection with the Offering.

 

(m) Pro forma adjustment to reflect the incurrence of interest expense on $88.2 million of additional borrowings under our revolving credit facility used to fund the Beta Acquisition. For the year ended December 31, 2011, pro forma interest expense was based on a rate of 2.81% and for the nine months ended September 30, 2012, interest expense was based on a rate of 2.79%. A one-eighth percentage point change in the interest rate would change pro forma interest by $0.1 million for both the year ended December 31, 2011 and the nine months ended September 30, 2011.

 

(n) Pro forma adjustment to reflect the incurrence of interest expense on $293.0 million of borrowings outstanding under our revolving credit facility prior to the Beta Acquisition. This $293.0 million consists of $120.0 million related to our IPO in December 2011 and $173.0 million to acquire assets from third parties and Memorial Resource in 2012. For pro forma interest expense purposes, this $293.0 million was assumed to be outstanding since January 1, 2011. For the year ended December 31, 2011, pro forma interest expense was based on a rate of 2.81% for borrowings outstanding and 0.5% for commitment fees on the unused borrowing base.

For the nine months ended September 30, 2012, pro forma adjustment to reflect the incurrence of interest expense as if the $293.0 million was outstanding for the nine months. The pro forma adjustment was based on a rate of 2.79% for borrowings outstanding and 0.5% for commitment fees on the unused borrowing base.

A one-eighth percentage point change in the interest rate would change pro forma interest by $0.4 million for the year ended December 31, 2011 and $0.3 million for the nine months ended September 30, 2011.

 

(o) Pro forma adjustment of $1.0 million for the nine months ended September 30, 2012 to reflect the reduction in historical interest expense associated with Rise’s debt that was repaid in connection with the Offering.

 

(p) Pro forma adjustment to reflect the amortization of deferred financing costs as if the borrowing costs associated with the Beta Acquisition, Third Party Acquisitions and IPO Related Transactions were incurred on January 1, 2011.

 

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Table of Contents

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

 

Note 3. Historical and Pro Forma Net Income Per Limited Partner Unit

Our historical allocation of net income to limited partners and earnings per unit included under the “Partnership Historical” column in the unaudited pro forma condensed combined statements of operations for the year ended December 31, 2011 and nine months ended September 30, 2012 includes only the net income attributable to our limited partners and general partner for each of the respective periods. Also included in the “Net income (loss) attributable to partners and predecessor” caption on the pro forma condensed combined statements of operations for the year ended December 31, 2011 and nine months ended September 30, 2012 are amounts attributable to our predecessor and are not included in our historical allocation of income to the partners or historical earnings per unit.

Pro forma net income per limited partner unit is determined by dividing the pro forma net income available to holders of common units, after deducting the general partner’s 0.1% interest in pro forma net income, by the number of common units and subordinated units expected to be outstanding at the closing of the Offering. For purposes of this calculation, we assumed the aggregate number of common units outstanding were 26,894,627 for the year ended December 31, 2011 and 27,380,190 for the nine months ended September 30, 2012 and 5,360,912 subordinated units outstanding for both periods. Basic and diluted pro forma net income per unit are equivalent as there will no dilutive units at the date of the closing of the Offering.

Note 4. Pro Forma Proved Reserves and Standardized Measure of Discounted Future Net Cash Flows

Estimated Quantities of Proved Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will continue the project within a reasonable time.

Estimated proved reserves presented in the table below were either prepared or audited by independent third-party petroleum engineers or estimated by management. As of December 31,

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

 

2011, approximately 85% of the proved reserves included in the “Partnership Historical” column in the table below were prepared by Netherland, Sewell & Associates (“NSAI”) and the remainder were prepared by management. All of the proved reserves related to the Beta Acquisition were also prepared by NSAI while the proved reserves associated with the 2012 Third Party Acquisitions were estimated by management.

The following table illustrates the Partnership’s pro forma estimated net proved reserves as of December 31, 2011. The oil price as of December 31, 2011 is based on the twelve month unweighted average of the first of month prices of the West Texas Intermediate posted price which equates to $92.71 per barrel. The oil and natural gas liquids prices were adjusted by lease for quality, transportation fees, and regional price differentials. The gas price as of December 31, 2011 is based on the twelve month unweighted average of the first of month prices of the Henry Hub spot price which equates to $4.118 per MMBtu. All prices are adjusted by lease for quality of energy content, transportation fees and regional price differentials. All prices are held constant in accordance with SEC rules.

 

     December 31, 2011  
     Partnership
Historical
     Rise
Historical
     2012 Third
Party

Acquisition
     Partnership
Pro Forma
Combined
 

Proved developed and undeveloped reserves:

           

Gas (MMcf)

     328,216                 104,098         432,314   

Oil (MBbls)

     2,408         12,779         2,789         17,976   

NGL(MBbls)

     6,763                 7,682         14,445   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total proved (MMcfe)

     383,241         76,674         166,924         626,839   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total proved developed (MMcfe)

     285,950         60,180         48,278         394,408   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total proved undeveloped (MMcfe)

     97,291         16,494         118,646         232,431   
  

 

 

    

 

 

    

 

 

    

 

 

 

A variety of methodologies are used to determine proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

The standardized measure of discounted future net cash flows presented below is computed by applying first of month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Partnership’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first of month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

 

The December 31, 2011 pro forma standardized measure of discounted future net cash flows is as follows:

 

     December 31, 2011  
     Partnership
Historical
    Rise
Historical
    2012 Third
Party

Acquisition
    Partnership
Pro Forma
Combined
 

Future cash inflows

   $ 1,894,818      $ 1,339,894      $ 950,478      $ 4,185,190   

Future production costs

     (648,781     (488,173     (217,998     (1,354,952

Future development costs

     (156,192     (67,681     (169,843     (393,716
  

 

 

   

 

 

   

 

 

   

 

 

 

Future net cash flows before 10% discount

     1,089,845        784,040        562,637        2,436,522   

10% annual discount for estimated timing of cash flows

     (625,946     (421,096     (362,413     (1,409,455
  

 

 

   

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

   $ 463,899      $ 362,944      $ 200,224      $ 1,027,067   
  

 

 

   

 

 

   

 

 

   

 

 

 

We are subject to certain state taxes. Due to immateriality we have excluded the impact of these taxes in the above table.

 

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Independent Auditors’ Report

The Board of Directors

Rise Energy Operating, LLC:

We have audited the accompanying consolidated balance sheets of Rise Energy Operating, LLC as of December 31, 2011 and 2010, and the related consolidated statements of operations, owners’ equity, and cash flows for the years ended December 31, 2011 and 2010 and for the period from February 3, 2009 (Inception) to December 31, 2009. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Rise Energy Operating, LLC as of December 31, 2011 and 2010, and the results of its operations and its cash flows for the years ended December 31, 2011 and 2010 and the period from February 3, 2009 to December 31, 2009 in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Dallas, Texas

March 30, 2012

 

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RISE ENERGY OPERATING, LLC

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

 

     DECEMBER 31,  
     2011     2010  
ASSETS   

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 8,066      $ 11,534   

Accounts receivable

     16,705        14,279   

Prepaid expenses and other current assets

     2,698        2,346   
  

 

 

   

 

 

 

Total current assets

     27,469        28,159   

PROPERTY AND EQUIPMENT:

    

Oil and natural gas properties, at cost, using the full cost method of accounting

     113,628        94,748   

Accumulated depletion

     (15,009     (7,994
  

 

 

   

 

 

 

Net oil and natural gas properties

     98,619        86,754   

Furniture, fixtures and equipment, net of $82 and $26 depreciation, respectively

     389        202   
  

 

 

   

 

 

 

Net property and equipment

     99,008        86,956   

OTHER LONG-TERM ASSETS:

    

Commodity derivative assets—non-current portion

     1,713          

Restricted investments

     63,619        58,964   

Other assets, net of $29 and $236 amortization, respectively

     446        378   
  

 

 

   

 

 

 

Total assets

   $ 192,255      $ 174,457   
  

 

 

   

 

 

 
LIABILITIES AND MEMBERS’ EQUITY   

CURRENT LIABILITIES:

    

Accounts payable

   $ 8,740      $ 4,937   

Accrued liabilities

     13,967        7,299   

Commodity derivative liabilities—current portion

     2,480        1,593   
  

 

 

   

 

 

 

Total current liabilities

     25,187        13,829   

NON-CURRENT LIABILITIES:

    

Asset retirement obligations

     56,428        54,080   

Note payable

     35,000          

Deferred tax liability

     1,688        1,833   

Commodity derivative liabilities—non-current portion

            1,778   
  

 

 

   

 

 

 

Total liabilities

     118,303        71,520   

COMMITMENTS AND CONTINGENCIES (Note 11)

    

EQUITY:

    

Members

     68,795        97,634   

Non-controlling interest

     5,157        5,303   
  

 

 

   

 

 

 

Total equity

     73,952        102,937   
  

 

 

   

 

 

 

Total liabilities and equity

   $ 192,255      $ 174,457   
  

 

 

   

 

 

 

See accompanying notes to these consolidated financial statements.

 

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RISE ENERGY OPERATING, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDING DECEMBER 31, 2011 AND 2010 AND FOR THE PERIOD

FROM FEBRUARY 3, 2009 (INCEPTION) TO DECEMBER 31, 2009

(dollars in thousands)

 

     2011     2010     2009  

REVENUE:

      

Oil and natural gas sales

   $ 60,744      $ 41,903      $   

Pipeline tariff income

     1,378        1,332          

Other

     1,439        645        680   
  

 

 

   

 

 

   

 

 

 
     63,561        43,880        680   

OPERATING EXPENSES:

      

Lease and pipeline operating expenses

     20,019        19,531          

Depletion of oil and natural gas properties

     7,015        7,717        37   

Depreciation of other property and equipment

     30        20        3   

Accretion of discount on asset retirement obligations

     2,348        2,252          

Acquisition costs

            201        66   

Management fee

     116        194          

General and administrative expenses

     4,186        4,411        608   
  

 

 

   

 

 

   

 

 

 

Total operating expenses

     33,714        34,326        714   
  

 

 

   

 

 

   

 

 

 

OPERATING INCOME (LOSS)

     29,847        9,554        (34

OTHER INCOME (EXPENSE):

      

Unrealized gain (loss) on commodity derivatives

     2,605        (3,372       

Realized loss on commodity derivatives

     (1,163     (162       

Amortization of investment premium

     (606     (907       

Interest income

     1,137        1,445          

Interest expense and related costs

     (856     (448       

Other

     (28     (1       
  

 

 

   

 

 

   

 

 

 

Total other income (expense)

     1,089        (3,445       
  

 

 

   

 

 

   

 

 

 

INCOME BEFORE TAX

     30,936        6,109        (34

Income tax benefit

     65        9          
  

 

 

   

 

 

   

 

 

 

NET INCOME (LOSS)

     31,001        6,118        (34

Net loss attributable to non-controlling interest

     146        8          
  

 

 

   

 

 

   

 

 

 

NET INCOME (LOSS) ATTRIBUTABLE TO OWNERS’ EQUITY

   $ 31,147      $ 6,126      $ (34
  

 

 

   

 

 

   

 

 

 

See accompanying notes to these consolidated financial statements.

 

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RISE ENERGY OPERATING, LLC

CONSOLIDATED STATEMENTS OF OWNERS’ EQUITY

FOR THE YEARS ENDING DECEMBER 31, 2011 AND 2010 AND FOR THE PERIOD

FROM FEBRUARY 3, 2009 (INCEPTION) TO DECEMBER 31, 2009

(dollars in thousands)

 

     Non-controlling
Interest
    Owners     Total  

BALANCES, February 3, 2009 (Inception)

   $      $      $   

Capital contributions

            89,297        89,297   

Fair value of non-controlling interest in acquisition

     4,105               4,105   

Net loss

            (34     (34
  

 

 

   

 

 

   

 

 

 

BALANCES, December 31, 2009

     4,105        89,263        93,368   

Capital contributions

     1,206        6,630        7,836   

Cash distributions

            (4,385     (4,385

Net income (loss)

     (8     6,126        6,118   
  

 

 

   

 

 

   

 

 

 

BALANCES, December 31, 2010

     5,303        97,634        102,937   

Capital contributions

            5,010        5,010   

Cash distributions

            (64,996     (64,996

Net income (loss)

     (146     31,147        31,001   
  

 

 

   

 

 

   

 

 

 

BALANCES, December 31, 2011

   $ 5,157      $ 68,795      $ 73,952   
  

 

 

   

 

 

   

 

 

 

See accompanying notes to these consolidated financial statements.

 

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RISE ENERGY OPERATING, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDING DECEMBER 31, 2011 AND 2010 AND FOR THE PERIOD

FROM FEBRUARY 3, 2009 (INCEPTION) TO DECEMBER 31, 2009

(dollars in thousands)

 

    2011     2010     2009  

CASH FLOWS FROM OPERATING ACTIVITIES:

     

Net income (loss)

  $ 31,001      $ 6,118      $ (34

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:

     

Depletion and depreciation

    7,071        7,741        40   

Accretion of discount on asset retirement obligations

    2,348        2,252          

Amortization of bond premium

    606        907          

Amortization of debt issuance costs

    407        236          

Unrealized loss on commodity derivatives

    (2,605     3,372          

Income tax benefit

    (65     (9       

Changes in operating assets and liabilities:

     

Accounts receivable

    (2,426     (14,179     (100

Prepaid expenses and other current assets

    (352     (963     (1,382

Accounts payable

    3,803        4,786        150   

Other assets and liabilities

    2,162        7,295        2   
 

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) operating activities

    41,950        17,556        (1,324
 

 

 

   

 

 

   

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

     

Additions to oil and natural gas properties

    (14,452     (5,335       

Additions to furniture, fixtures and equipment

    (243     (202     (26

Additions to restricted investments

    (5,261     (3,368     (4,676

Acquisition of oil and gas properties

                  (87,331
 

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

    (19,956     (8,905     (92,033
 

 

 

   

 

 

   

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

     

Contribution from non-controlling interest

           1,206        4,105   

Contribution from owners

    5,010        6,630        89,297   

Distributions to owners

    (64,996     (4,385       

Proceeds from issuance of debt

    40,000                 

Repayment of debt

    (5,000              

Loan fees and related costs

    (476     (613       
 

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) financing activities

    (25,462     2,838        93,402   
 

 

 

   

 

 

   

 

 

 

NET CHANGE IN CASH

    (3,468     11,489        45   

CASH, beginning of period

    11,534        45          
 

 

 

   

 

 

   

 

 

 

CASH, end of period

  $ 8,066      $ 11,534      $ 45   
 

 

 

   

 

 

   

 

 

 

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:

     

Interest paid

  $ 263      $      $   
 

 

 

   

 

 

   

 

 

 

Taxes paid

  $ 40      $      $   
 

 

 

   

 

 

   

 

 

 

Non-cash capital expenditures in liabilities

  $ 4,428      $      $   
 

 

 

   

 

 

   

 

 

 

See accompanying notes to these consolidated financial statements.

 

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Table of Contents

RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

Note 1—Organization

Rise Energy Operating, LLC (“REO” or “Company”) a Delaware limited liability company, was formed on September 20, 2011. The Company conducts its operations through its wholly owned subsidiaries, Rise Energy Operating, Inc., a Delaware corporation formed on February 3, 2009, Rise Energy Minerals, LLC, a Delaware limited liability company formed on November 25, 2009, Rise Energy Beta, LLC, a Delaware limited liability company formed on November 25, 2009, and Beta Operating Company, LLC, a Delaware limited liability company formed on November 25, 2009. Rise Energy Beta, LLC holds a 51.75% interest in the common stock of San Pedro Bay Pipeline Company (“SPBPC”), a California corporation, acquired on December 30, 2009. Prior to the formation of REO, its current subsidiaries were all affiliates under Rise Energy Partners, LP, a Texas limited partnership (“REP”). On September 20, 2011, upon formation of REO, the aforementioned affiliates were reorganized as subsidiaries of REO. No change in carrying values of assets and liabilities occurred as part of the reorganization of interests under common control.

The Company was formed to acquire, develop and produce oil and natural gas properties. The Company’s oil and gas reserves are located offshore southern California in federal waters.

Note 2—Basis of Presentation and Significant Accounting Policies

(a) Basis of Presentation

The accompanying financial statements have been prepared under accounting principles generally accepted in the United States (“GAAP”). The financial statements include the consolidated results of Rise Energy Operating, LLC and its wholly owned subsidiaries . The ownership interest of the non-controlling shareholder in San Pedro Bay Pipeline Company is presented as non-controlling interest in the financial statements. All material intercompany balances and transactions have been eliminated.

(b) Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting period.

Significant estimates include, but are not limited to, oil and gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of assets acquired and liabilities assumed in business combinations and asset retirement obligations. Actual results could differ from the estimates.

(c) Cash and Cash Equivalents

All highly liquid investments with an original maturity of three months or less are considered to be cash equivalents.

 

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Table of Contents

RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

(d) Concentration of Credit Risk and Significant Customers

Financial instruments which potentially subject the Company to credit risk consist principally of cash balances, accounts receivable and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Derivative financial instruments are generally executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. The Company also has netting arrangements in place with counterparties to reduce credit exposure. The Company has not experienced any losses from such investments.

In 2011, 2010 and 2009 the Company sold all of its oil production to one customer. If the Company were to lose its customer, the loss could temporarily delay production and sale of oil; however, management believes that a substitute customer to purchase the impacted production volumes could be identified. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company’s customer base. Management determines amounts to be uncollectable when the Company has used all reasonable means of collection and settlement. Amounts outstanding longer than the contractual terms are considered past due. Management believes all amounts included in accounts receivable at December 31,2011 and 2010 will be collected, and therefore, no allowance for uncollectible accounts has been recorded.

(e) Depreciation, Depletion and Amortization of Property and Equipment

The Company follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.

Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net revenues, discounted at 10% per annum, from proved oil, gas and NGL reserves plus the cost of properties not subject to amortization. Estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties.

Future net revenues are calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of the period. Prices and costs used to calculate future net revenues were those as of the end of the appropriate quarterly period. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts.

Any excess of the net book value, less related deferred income taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period

 

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Table of Contents

RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

even though higher commodity prices may have increased the ceiling applicable to the subsequent period. No impairment of the net capitalized costs due to the full-cost limitation was necessary in 2011, 2010 or 2009.

Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.

(f) Asset Retirement Obligations

The Company accounts for asset retirement obligations under ASC Topic 410, Asset Retirement and Environmental Obligations. ASC 410 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Under ASC 410, the liability for an asset retirement obligation is recorded at the asset’s inception, discounted to its present value using a credit-adjusted risk free interest rate. Typically, a corresponding amount is capitalized as an asset to the full cost pool. The liability is accreted each period and the asset is depreciated using the unit-of-production method as described above. Revisions to the estimated retirement obligation will result in an adjustment to the related asset and liability. If the liability is settled at an amount that differs from the recorded amount, unless significant, the difference is recorded to the full cost pool.

(g) Inventory

Inventory consists of oil volumes maintained within pipelines and storage tanks. The inventory volumes are recorded at lower of cost or market value. No market adjustment was required in 2011, 2010 or 2009.

(h) Debt Issuance Costs

Debt issuance costs were incurred to obtain financing under the revolving credit facility (see Note 8). These costs are recorded on the balance sheet and amortized over the term of the debt using the straight-line method which approximates the effective yield method.

(i) Revenue Recognition

The Company follows the sales method of accounting for oil revenue whereby revenue is recognized based on actual volumes of oil sold to purchasers. The Company and other joint interest owners may sell more or less than their entitlement share of volumes produced. Differences between oil and natural gas volumes sold and volumes to which the Company is entitled create imbalances. No material imbalances existed as of December 31, 2011 and 2010.

(j) Derivative Instruments and Hedging Activities

The Company may enter into commodity derivative instruments to reduce its exposure to fluctuations in commodity prices related to its forecasted oil and natural gas production. The Company has elected not to designate any of its positions for hedge accounting for financial

 

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Table of Contents

RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

statement purposes. Accordingly, the Company records the net change in the fair value of the instruments, as well as payments and receipts on settled contracts, in other income or expense on the statement of operations. The unrealized gains or losses on open commodity derivative positions are recorded at fair value on the Company’s balance sheet as current or non-current assets or liabilities based on the anticipated timing of the related cash flows.

(k) Income Taxes

Rise Energy Operating, LLC has elected partnership status for income tax purposes and therefore does not pay income taxes.

Rise Energy Operating, Inc. and San Pedro Bay Pipeline Company are corporations and are subject to federal taxes. The Company records deferred tax assets and liabilities for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates of deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change.

(l) New Accounting Pronouncements

In April 2010, the FASB issued ASU 2010-14, which amends the guidance on oil and natural gas reporting in Accounting Standards Codification 932.10.S99-1 by adding the Codification of SEC Regulation S-X, Rule 4-10 as amended by the SEC Final Rules 33-8995. ASU 2010-14 is effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments.

In January 2010, the FASB issued Accounting Standards Update (“ASU”) 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements. ASU 2010-06 requires reporting entities to provide information about movements of assets amount Levels 1 and 2 of the three-tier fair value hierarchy established by FASB ASC 820. The guidance is effective for any fiscal year that begins after December 15, 2009.

Note 3—Acquisitions

Acquisitions of producing oil and gas properties meet the definition of a business under the Financial Accounting Standards Codification (“FASC”) “Business Combinations” topic. As such, the Company was required to record each property at its estimated fair value as of the acquisition date.

The fair value of oil and gas properties was based on significant inputs not observable in the market, which accounting standards define as Level 3 inputs. Key assumptions include (1) NYMEX oil and natural gas futures (this input is observable), (2) estimates of oil and natural gas reserves, (3) estimates of future production, and (4) timing and amount of future costs. All transaction related costs (legal, accounting, due diligence, etc.) are expensed.

 

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Table of Contents

RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

California Override Acquisition

On November 6, 2009, REP acquired a 4.575% overriding royalty interest in producing offshore California oil wells from J. Aron & Company for a net purchase price of $16.2 million which REP subsequently contributed to Rise Energy Minerals, LLC, a wholly-owned subsidiary of the Company.

California Working Interest Acquisition

Simultaneous with acquiring the royalty interest, REP acquired from J. Aron & Company, 50.7% of the combined outstanding debt of Pacific Energy Resources, Ltd. (“PERL”) for $68.8 million, representing a $176.2 million discount from the face value of the debt of $245.0 million.

On December 30, 2009, REP purchased certain assets and assumed certain future liabilities of PERL through a competitive credit bid under Section 363 of the United States Bankruptcy Code. Under the terms of the credit bid and resulting Sale Order, REP and an unaffiliated company exchanged the then outstanding notes receivable from PERL and approximately $1.4 million in cash, net to REP, for undivided interests in three offshore California platforms, the common stock of San Pedro Bay Pipeline Company (“SPBPC”) (collectively, the “Beta Unit”) and certain prepaid assets while assuming certain future platform and pipeline retirement obligations. No gain or loss was recognized on conversion of the PERL debt. Concurrent with the consummation of the credit bid, REP contributed the resulting undivided 51.75% working interest in the Beta Unit to Rise Energy Beta, LLC.

The SPBPC assets consist of a pipeline between the offshore platforms and onshore facilities and certain restricted cash accounts. The Company determined the fair value of its ownership in SPBPC and the 48.25% non-controlling interest in SPBPC in conjunction with the valuation of the oil properties since the economic benefit of the pipeline is dependent upon the oil reserves.

The Company estimated the final fair value of the assets and liabilities acquired as follows (in thousands):

 

Proved oil and gas properties

   $ 73,710   

Restricted investments

     56,092   

Inventory—oil volumes

     440   

Prepaid assets

     878   

Non-controlling interest

     (4,105

Deferred tax liability

     (1,843

Asset retirement obligation

     (51,417
  

 

 

 

Total

   $ 73,755   
  

 

 

 

The fair value of the deferred tax liabilities was finalized during 2011 upon receipt of the SPBPC prior period tax returns. Based on this valuation, the Company retrospectively recognized a deferred tax liability of $1.843 million and increased the fair value of the proved oil and gas properties by $1.843 million as of December 31, 2009.

 

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Table of Contents

RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

Note 4—Fair Value Measurement of Financial Instruments

The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonable available without undue cost and effort. These two types of inputs are further divided into the following fair value input hierarchy:

Level 1—Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2—Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange-traded derivatives, such as over-the-counter commodity price swaps, collars, put options and interest rate swaps. At December 31, 2011 and 2010, all of the Company’s derivative instruments were considered Level 2.

Level 3—Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity).

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The carrying values of cash and cash equivalents, accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements included in the accompanying consolidated balance sheets approximated fair value at December 31, 2011 and 2010. These assets and liabilities are not presented in the following tables.

Derivative Instruments—The fair market values of the derivative financial instruments reflected in the balance sheets were based on quotes obtained from the counterparties to the agreements. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

 

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Table of Contents

RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

The fair value input hierarchy to which an asset or liability measurement falls is determined based on the lowest-level input that is significant to the measurement in its entirety. The following table presents the Company’s assets and liabilities that are measured at fair value on a recurring basis at December 31, 2011 and 2010 for each of the fair value hierarchy levels (in thousands):

 

     Fair Value Measurement at December 31, 2011 Using  
     Quoted
Prices in
Active
Markets
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs

(Level 3)
     Fair
Value at
December 31,
2011
 

Assets:

           

Commodity derivative collar contracts

   $       $ 1,713       $       $ 1,713   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

   $       $ 1,713       $       $ 1,713   
  

 

 

    

 

 

    

 

 

    

 

 

 

Liabilities:

           

Commodity derivative collar contracts

   $       $ 2,480       $       $ 2,480   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total liabilities

   $       $ 2,480       $       $ 2,480   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

     Fair Value Measurement at December 31, 2010 Using  
     Quoted
Prices in
Active
Markets
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs

(Level 3)
     Fair
Value at
December 31,
2011
 

Assets:

           

Commodity derivative collar contracts

   $       $       $       $   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

   $       $       $       $   
  

 

 

    

 

 

    

 

 

    

 

 

 

Liabilities:

           

Commodity derivative collar contracts

   $       $ 3,371       $       $ 3,371   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total liabilities

   $       $ 3,371       $       $ 3,371   
  

 

 

    

 

 

    

 

 

    

 

 

 

For additional information on the Company’s derivative instruments, see Note 5.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis:

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s balance sheets. The following methods and assumptions were used to estimate the fair values:

Asset Retirement Obligations (ARO’s)—The Company estimates the fair value of ARO’s based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. See Note 6 for a summary of changes in ARO’s.

 

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Table of Contents

RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

Properties Acquired in Business Combinations—If sufficient market data is not available, the Company determines the fair values of proved and unproved properties acquired in transactions accounted for as business combinations by preparing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.

Note 5—Risk Management and Derivative Instruments

The Company utilizes derivative instruments to manage exposure to commodity price and achieve a more predictable cash flow in connection with its oil sales from production. These transactions limit exposure to declines in prices, but also limit the benefits the Company would realize if prices increase.

Inherent in the Company’s portfolio of oil derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into master netting agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty.

(a) Commodity Derivatives

The Company uses a combination of crude oil costless collars and put options to manage its exposure to oil price volatility. At December 31, 2011, the Company had the following open commodity positions.

 

Crude Oil Collars

 

Beginning

         Month          

  Ending
Month
  Index   Average
Monthly
Volumes  (bbls)
    Weighted
Average

Floor
    Weighted
Average

Ceiling
 

1/1/2012

  12/31/2012   WTI     20,000      $ 70.00      $ 97.50   

1/1/2012

  12/31/2012   WTI     10,000      $ 80.00      $ 101.50   

1/1/2012

  12/31/2012   Brent     10,000      $ 90.00      $ 116.50   

1/1/2013

  12/31/2013   WTI     10,000      $ 95.00      $ 116.65   

1/1/2013

  12/31/2013   WTI     10,000      $ 95.00      $ 119.15   

1/1/2013

  12/31/2013   Brent     10,000      $ 90.00      $ 108.75   

 

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Table of Contents

RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

(b) Balance Sheet Presentation

The following table summarizes the gross fair value of derivative instruments by appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets as December 31, 2011 and 2010 (in thousands).

 

          December 31,  

Type

  

Balance Sheet Location

   2011     2010  

Crude oil collars

   Current assets    $ 397      $   

Crude oil collars

   Long-term asset      1,836          

Crude oil collars

   Current liabilities      (2,877     (1,593

Crude oil collars

   Long-term liabilities      (123     (1,778
     

 

 

   

 

 

 

Net derivative financial instruments

   $ (767   $ (3,371
     

 

 

   

 

 

 

 

(1) The fair value of the derivative instruments reported in the Company’s consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table reports the net derivative fair values as reported in the Company’s consolidated balance sheets at December 31, 2011 and 2010.

 

     December 31,  
     2011     2010  

Consolidated balance sheet classification:

    

Current derivative contracts:

    

Assets

   $ 397      $   

Liabilities

     (2,877     (1,593
  

 

 

   

 

 

 

Net current

   $ (2,480   $ (1,593
  

 

 

   

 

 

 

Noncurrent derivative contracts:

    

Assets

   $ 1,836      $   

Liabilities

     (123     (1,778
  

 

 

   

 

 

 

Net noncurrent

   $ 1,713      $ (1,778
  

 

 

   

 

 

 

(c) Gains (Losses) on Derivatives

The Company does not designate instruments as hedging instruments for financial reporting purposes. Accordingly, all gains and losses, including unrealized gains and losses from changes in the derivative instruments’ fair values, have been recorded in the consolidated statements of operations. The following table details the unrealized and realized gains and losses related to derivative instruments for the years ending December 31, 2011, 2010 and 2009 (in thousands):

 

     Statements of
Operations Location
     Years Ended December 31,  
      2011      2010     2009  

Commodity derivative contracts (1)

     Gain on derivatives       $ 1,442       $ (3,534   $   

 

(1) Included in these amounts are net cash payments of approximately $1.163 million and $0.162 million for the years ended December 31, 2011 and 2010, respectively.

 

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Table of Contents

RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

Note 6—Asset Retirement Obligations

The Company recognizes the fair value of its asset retirement obligations related to the plugging, abandonment, and remediation of oil and gas producing properties. The present value of the estimated asset retirement costs has been capitalized as part of the carrying amount of the related long-lived assets. The Company’s estimated asset retirement costs for the offshore oil and gas wells reflect the costs published by the Bureau of Ocean Energy Management, Regulation, and Enforcement (“BOEMRE”), formerly known as Minerals Management Service.

The liability has been accreted to its present value as of December 31, 2011 and 2010. The following table represents a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2011, 2010, and 2009 (in thousands):

 

     2011      2010      2009  

Asset retirement obligations at beginning of year

   $ 54,080       $ 51,417       $   

Liabilities added from acquisitions or drilling

                     51,417   

Current year accretion expense

     2,348         2,252           

Increase due to ownership change *

             411           

Revision of estimates

                       
  

 

 

    

 

 

    

 

 

 

Asset retirement obligations at end of year

   $ 56,428       $ 54,080       $ 51,417   
  

 

 

    

 

 

    

 

 

 

 

* In 2009 the Company’s retirement obligation related to the San Pedro Bay pipeline was reflected on the books of Rise Energy Beta. During 2010 the cash collateral account related to this obligation was transferred to SPBPC and as such the obligation was also transferred. Because SPBPC is fully consolidated, the obligation was increased to include the portion attributable to the non-controlling interest at December 31, 2009.

Note 7—Restricted Investments

On December 30, 2009 in conjunction with the California working interest acquisition (see Note 3), the Company acquired various restricted investment accounts that fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds.

The components of the restricted investment balance at December 31, 2011 are as follows:

 

     (in thousands)  
     2011      2010  

BOEMRE platform abandonment (See Note 11)

   $ 57,348       $ 53,069   

BOEMRE lease bonds

     776         776   

SPBPC Collateral *:

     

Contractual pipeline and surface facilities abandonment (See Note 11)

     1,595         1,219   

California State Lands Commission pipeline right-of-way bond

     3,000         3,000   

City of Long Beach pipeline facility permit

     500         500   

Federal pipeline right-of-way bond

     300         300   

Port of Long Beach pipeline license

     100         100   
  

 

 

    

 

 

 

Restricted investments

   $ 63,619       $ 58,964   
  

 

 

    

 

 

 

 

* These investments reside with SPBPC. Because SPBPC is fully consolidated, the amounts shown include the portion attributable to the non-controlling interest at December 31, 2011.

 

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Table of Contents

RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

Note 8—Long Term Debt

In March 2010, Rise Energy Beta, LLC and Rise Energy Minerals, LLC entered into a $50.0 million revolving line of credit with BNP Paribas. On December 31, 2010, the $50.0 million credit facility was amended to extend the maturity date to December 31, 2012, with quarterly principal payments beginning on March 31, 2012. On October 26, 2011, the Company refinanced this credit facility and entered into a $150.0 million revolving credit facility with BNP Paribas as Administrative Agent. Amounts outstanding under the new credit facility are payable on October 26, 2014. At December 31, 2011, $35.0 million was outstanding under the credit facility. No debt was outstanding at December 31, 2010.

Amounts outstanding under the $150.0 million credit facility are limited to a borrowing base which is determined twice per year. In addition, the Company and Administrative Agent can request special borrowing base determinations, from time to time. The borrowing base was $50.0 million at December 31, 2011 and the borrowing base availability was $15.0 million at December 31, 2011.

Amounts outstanding under the credit facility elected as Eurodollar loans bear interest at the LIBOR rate plus a margin ranging from 2.25% to 3.25% payable at the end of the LIBOR loan period, not to exceed three months. Amounts outstanding subject to the Alternative Base Rate loan bear interest at a margin ranging from 1.25% to 2.25% plus the greater of the prime rate, federal funds effective rate plus a margin of 0.50%, or LIBOR rate plus a margin of 1%. Interest is payable quarterly. Amounts outstanding under the facility for the year ended December 31, 2011 were at a weighted average interest rate of approximately 3.03%. A commitment fee of 0.5% on the unused portion of the credit facility is payable quarterly in arrears.

The Company’s borrowings are secured by its assets and are subject to various financial and nonfinancial covenants. Significant financial covenants include maintaining: (1) a minimum current ratio, as defined, of 1.0 to 1.0, and (2) a maximum of debt to EBITDAX ratio for the previous four quarters, as defined, of 3.5 to 1.0. At December 31, 2011 and 2010, the Company was in compliance with its debt covenants.

 

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Table of Contents

RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

Note 9—Income Taxes

Income tax expense differs from the amount computed by applying the federal income tax rate to income before income taxes in 2011 primarily as a result of income tax expense being generated by consolidated subsidiaries and depreciation. Components of income tax expense (benefit) consist of the following (in thousands):

 

     For the Year Ended
December 31,
 
     2011     2010     2009  

Current:

      

Federal

   $ 75      $      $   

State

     3        1          
  

 

 

   

 

 

   

 

 

 
   $ 78      $ 1      $   
  

 

 

   

 

 

   

 

 

 

Deferred:

      

Federal

     (139     (8       

State

     (4     (2       
  

 

 

   

 

 

   

 

 

 
     (143     (10       
  

 

 

   

 

 

   

 

 

 

Total

   $ (65   $ (9   $   
  

 

 

   

 

 

   

 

 

 

The following is a summary of the significant components of the Company’s deferred tax assets and (liabilities) (in thousands):

 

     December 31,  
     2011     2010  

Current deferred tax assets (liabilities):

    

Prepaid expenses

   $ (2   $   
  

 

 

   

 

 

 
   $ (2   $   
  

 

 

   

 

 

 

Noncurrent deferred tax assets (liabilities):

    

Depreciation

   $ (2,539   $ (2,260

Net operating loss

     482        318   

Other

     369        354   

Valuation allowance

            (245
  

 

 

   

 

 

 

Net deferred tax liability

   $ (1,688   $ (1,833
  

 

 

   

 

 

 

At December 31, 2011, the Company has net operating loss carryforwards for federal income tax purposes of approximately $0.143 million which will expire in 2030 and $1.127 million which expire in 2031. In addition, the Company has state net operating losses of approximately $0.143 million which will expire in 2030 and $0.719 million which expire in 2031.

 

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Table of Contents

RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

Note 10—Related Party Transactions

The Company, as a subsidiary of REP, has agreed to perform, either itself or through its affiliates, administrative services for REP and REP has agreed to reimburse the Company for its expenses incurred in providing such services. These administrative services may include accounting, business development, finance, legal, information technology, insurance, government regulations, communications, regulatory, environmental and human resources services. Expenses are reimbursed based on the determination of a management fees as deemed necessary. For the years ended December 31, 2011, 2010 and 2009, REP paid management fees to the Company in the amounts of $1.2 million, $0.2 million and $0.7 million, respectively. Management fees received from REP are presented as other revenue.

Note 11—Commitments and Contingencies

Litigation

The Company may from time to time be involved in various claims, lawsuits, disputes with third parties, or breach of contract incidental to the operations of its business. The Company is not currently involved in any litigation which it believes could have a materially adverse effect on its financial condition or results of operations.

Environmental

The Company is subject to extensive environmental laws and regulations. These laws, which are subject to change, regulate the discharge of materials into the environment and maintenance of surface conditions and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. As of December 31, 2011, the Company is not aware of any material environmental remediation obligations.

Sinking Fund Trust Agreement

In conjunction with the California working interest acquisition (Note 3), the Company assumed an obligation with a third party to make payments into a sinking fund, the purpose of which is to provide funds adequate to decommission the portion of the San Pedro Bay pipeline that lies within State waters and the surface facilities. Under the terms of the agreement, the Company, as the operator of the properties, is obligated to make monthly deposits into the sinking fund account in an amount equal to $0.25 per barrel of oil and other liquid hydrocarbon produced from the acquired working interest. Interest earned in the account stays in the account. The obligation to fund ceases when the aggregate value of the account reaches $4.3 million. As of December 31, 2011, the gross account balance included in restricted investments was $1.6 million. The Company’s maximum remaining obligation net to its 51.75% interest under the terms of the current agreement was $1.4 million at December 31, 2011.

 

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Table of Contents

RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

Supplemental Bond for Decommissioning Liabilities Trust Agreement

Also in conjunction with the California working interest acquisition, the Company assumed an obligation with the BOEMRE. Under the terms of the agreement dated March 1, 2007, the seller of the working interests was obligated to deliver a $90 million U.S. Treasury Note into a trust account for the decommissioning of the offshore production facilities. At the time of acquisition, all obligations under this existing agreement had been met.

In January 2010, the BOEMRE issued a report that revised upward, the estimated cost of decommissioning. In June 2010, the Company agreed to make additional quarterly payments to the trust account attributable to its net working interest of $0.647 million beginning on June 30, 2010 until the payments and accrued interest attributable to the Company equal $78.7 million by December 31, 2016. Beginning June 30, 2011, the trust account must maintain minimum balances attributable to the Company’s net working interest as follows (in thousands):

 

June 30, 2012

   $ 60,030   

June 30, 2013

     64,170   

June 30, 2014

     68,310   

June 30, 2015

     72,450   

June 30, 2016

     76,590   

December 31, 2016

     78,660   

In the event the account balance is less than the contractual amount, the working interest owners must make additional payments. As of December 31, 2011, the maximum remaining obligation net to the Company’s interest was approximately $20.4 million.

The trust account is held by the Company for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of December 31, 2011 (in thousands):

 

Investment

   Amortized
Cost
    Unrealized
Gain
(Loss)
    Fair
Market
Value
 

U.S. Bank Money Market Cash Equivalent

   $ 44,242      $      $ 44,242   

U.S. Government Treasury Note, maturity of March 31, 2012, and 4.50% coupon

     21,246        38        21,284   

U.S. Government Treasury Note, maturity of March 31, 2013, and 2.50% coupon

     22,365        334        22,699   

U.S. Government Treasury Note, maturity of March 31, 2014, and 1.75% coupon

     22,964        864        23,828   

Less: Outside working interest owners share

     (53,469     (597     (54,066
  

 

 

   

 

 

   

 

 

 
   $ 57,348      $ 639      $ 57,987   
  

 

 

   

 

 

   

 

 

 

 

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Table of Contents

RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

Office Lease

The Company leases administrative offices in Texas and California under non-cancelable operating leases. Commitments related to these lease payments are not recorded in the accompanying consolidated balance sheets. As of December 31, 2011, minimum future lease payments for all non-cancelable lease agreements were as follows (in thousands):

 

2012

   $ 301   

2013

     303   

2014

     244   

2015

     252   

2016

     149   
  

 

 

 

Total

   $ 1,249   
  

 

 

 

Note 12—Subsequent Events

No events or transactions have occurred subsequent to the balance sheet date, up until the date the financial statements were available to be issued, March 30, 2012, that would require recognition or disclosure in the financial statements.

Note 13—Supplemental Oil and Gas Information (Unaudited)

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization.

 

     December 31,  
     2011     2010     2009  
           (In thousands)        

Evaluated oil and natural gas properties (1)

   $ 100,938      $ 84,165      $ 83,126   

Unevaluated oil and natural gas properties

     3,719        2,108          

Accumulated depletion (1)

     (14,156     (7,571     (239
  

 

 

   

 

 

   

 

 

 
   $ 90,501      $ 78,702      $ 82,887   
  

 

 

   

 

 

   

 

 

 

 

(1) Amounts do not include costs for San Pedro Bay Pipeline and related support equipment.

 

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RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows:

 

     December 31,  
     2011      2010      2009  
            (In thousands)         

Property acquisition costs, proved

   $       $       $ 83,126   

Exploration and extension well costs

     683         836           

Development costs (1)

     17,701         2,310           
  

 

 

    

 

 

    

 

 

 

Total costs

   $ 18,384       $ 3,146       $ 83,126   
  

 

 

    

 

 

    

 

 

 

 

(1) Amounts do not include costs for San Pedro Bay Pipeline and related support equipment.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves

The following Standardized Measure of Discounted Future Net Cash Flows has been developed utilizing ASC 932, Extractive Activities—Oil and Gas, (ASC 932) procedures and based on oil and natural gas reserve and production volumes estimated by the Company’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account when reviewing the following information:

 

  Ÿ  

Future costs and selling prices will probably differ from those required to be used in these calculations;

 

  Ÿ  

Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;

 

  Ÿ  

A 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues

Under the Standardized Measure, for the years ended December 31, 2011, 2010 and 2009, the future cash inflows were estimated by applying unweighted twelve month average of the first day of the month cash price quotes to the estimated future production of period end proved reserves. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. Use of a 10% discount rate and the unweighted twelve month average price were required. The Company is an unincorporated entity, and as such, no income tax effects were included in determining the Standardized Measure.

 

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RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for the reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in financial statement disclosures.

Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will continue the project within a reasonable time.

The following table illustrates the Company’s estimated net proved reserves, including changes, and proved developed reserves for 2011 and 2010, as estimated by Netherland, Sewell & Associates, Inc. (NSAI), an independent, third-party petroleum engineer, and for 2009, as estimated by the Company. The oil prices as of December 31, 2011, 2010 and 2009 are based on the respective 12-month unweighted average of the first of the month prices of the WTI Posting (Plains) spot price which equates to $92.71, $75.96, and $61.18 per barrel. All prices are held constant in accordance with SEC rules. All proved reserves are located in the United States.

 

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RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

The oil reserves shown include crude oil only. Produced gas is currently flared or consumed in field operations.

 

     Proved Reserves  
     Oil (Mbbls)  

Proved reserves at December 31, 2008

       

Revisions of estimates

       

Purchase of minerals in place

     7,226   

Production

     (12
  

 

 

 

Proved reserves at December 31, 2009

     7,214   

Revisions of estimates

     3,770   

Purchase of minerals in place

       

Production

     (578
  

 

 

 

Proved reserves at December 31, 2010

     10,406   

Revisions of estimates

     2,964   

Purchase of minerals in place

       

Production

     (591
  

 

 

 

Proved reserves at December 31, 2011

     12,779   
  

 

 

 

 

     Proved Developed Reserves  
     Oil (Mbbls)  

Proved reserves at December 31, 2009

     5,348   

Proved reserves at December 31, 2010

     8,744   

Proved reserves at December 31, 2011

     10,030   

 

     Proved Undeveloped Reserves  
     Oil (Mbbls)  

Proved reserves at December 31, 2009

     1,866   

Proved reserves at December 31, 2010

     1,662   

Proved reserves at December 31, 2011

     2,749   

A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy.

 

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RISE ENERGY OPERATING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011, 2010 AND 2009

 

The Standardized Measure is as follows:

 

     Year Ended December 31,  
     2011     2010     2009  
           (In thousands)        

Future cash inflows

   $ 1,339,894      $ 756,936      $ 384,181   

Future production costs

     (488,173     (356,261     (150,878

Future development costs

     (67,681     (70,981     (80,474
  

 

 

   

 

 

   

 

 

 

Future net cash flows before 10% discount

     784,040        329,694        152,829   

10% annual discount for estimated timing of cash flows

     (421,096     (161,961     (58,129
  

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

   $ 362,944      $ 167,733      $ 94,700   
  

 

 

   

 

 

   

 

 

 

The Company’s oil and gas operations are owned by an entity not directly subject to federal taxation. As a result, no income taxes have been included in the determination of the Standardized Measure.

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2011:

 

     Year Ended December 31,  
     2011     2010     2009  
           (In thousands)        

Beginning of year

   $ 167,733      $ 94,700      $   

Sale of oil and natural gas produced, net of production cost

     (41,811     (22,871     (815

Changes in prices and costs

     127,881        20,811          

Net changes in future development costs

     (6,925     3,251          

Revision of previous quantities

     91,449        73,847          

Purchase of minerals in place

                   83,126   

Accretion of discount

     16,773        9,470          

Changes due to timing and other

     7,844        (11,475     12,389   
  

 

 

   

 

 

   

 

 

 

End of year

   $ 362,944      $ 167,733      $ 94,700   
  

 

 

   

 

 

   

 

 

 

 

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RISE ENERGY OPERATING, LLC

CONSOLIDATED BALANCE SHEETS

AS OF SEPTEMBER 30, 2012 AND DECEMBER 31, 2011

(dollars in thousands)

 

     SEPTEMBER 30,     DECEMBER 31,  
     2012     2011  
     (Unaudited)        
ASSETS   

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 6,100      $ 8,066   

Accounts receivable

     16,919        16,705   

Short-term derivative instruments

     730          

Prepaid expenses and other current assets

     1,585        2,698   
  

 

 

   

 

 

 

Total current assets

     25,334        27,469   

PROPERTY AND EQUIPMENT:

    

Oil and natural gas properties, at cost, using the full cost method of accounting

     120,518        113,628   

Accumulated depletion

     (20,201     (15,009
  

 

 

   

 

 

 

Net oil and natural gas properties

     100,317        98,619   

Furniture, fixtures and equipment, net of $168 and $82 depreciation, respectively

     488        389   
  

 

 

   

 

 

 

Net property and equipment

     100,805        99,008   

OTHER LONG-TERM ASSETS:

    

Commodity derivative assets—non-current portion

     456        1,713   

Restricted investments

     67,100        63,619   

Other assets, net of $147 and $29 amortization, respectively

     328        446   
  

 

 

   

 

 

 

Total assets

   $ 194,023      $ 192,255   
  

 

 

   

 

 

 
LIABILITIES AND MEMBERS’ EQUITY   

CURRENT LIABILITIES:

    

Accounts payable

   $ 6,201      $ 8,740   

Accrued liabilities

     10,406        13,967   

Commodity derivative liabilities—current portion

            2,480   
  

 

 

   

 

 

 

Total current liabilities

     16,607        25,187   

NON-CURRENT LIABILITIES:

    

Asset retirement obligations

     58,266        56,428   

Note payable

     30,000        35,000   

Deferred tax liability

     1,688        1,688   
  

 

 

   

 

 

 

Total liabilities

     106,561        118,303   

COMMITMENTS AND CONTINGENCIES (Note 9)

    

EQUITY:

    

Members

     82,288        68,795   

Non-controlling interest

     5,174        5,157   
  

 

 

   

 

 

 

Total equity

     87,462        73,952   
  

 

 

   

 

 

 

Total liabilities and equity

   $ 194,023      $ 192,255   
  

 

 

   

 

 

 

See accompanying notes to these consolidated financial statements.

 

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RISE ENERGY OPERATING, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011

(dollars in thousands)

 

     For the Nine Months
Ended September 30,
 
     2012     2011  
     (Unaudited)  

REVENUE:

    

Oil and natural gas sales

   $ 45,033      $ 44,425   

Pipeline tariff income

     1,076        1,017   

Other

     217        1,367   
  

 

 

   

 

 

 
     46,326        46,809   

OPERATING EXPENSES:

    

Lease and pipeline operating expenses

     15,467        14,833   

Depletion of oil and natural gas properties

     5,192        5,984   

Depreciation of other property and equipment

     21        22   

Accretion of discount on asset retirement obligations

     1,837        1,776   

Management fee

            87   

General and administrative expenses

     3,156        3,167   
  

 

 

   

 

 

 

Total operating expenses

     25,673        25,869   
  

 

 

   

 

 

 

OPERATING INCOME

     20,653        20,940   

OTHER INCOME (EXPENSE):

    

Unrealized gain on commodity derivatives

     1,953        9,102   

Realized loss on commodity derivatives

     (661     (954

Amortization of investment premium

     (170     (484

Interest income

     514        885   

Interest expense and related costs

     (993     (362

Other

     (36     (30
  

 

 

   

 

 

 

Total other income (expense)

     607        8,157   
  

 

 

   

 

 

 

INCOME BEFORE TAX

     21,260        29,097   

Income tax benefit

              
  

 

 

   

 

 

 

NET INCOME

     21,260        29,097   

Net gain (loss) attributable to non-controlling interest

     17        (229
  

 

 

   

 

 

 

NET INCOME ATTRIBUTABLE TO OWNERS’ EQUITY

   $ 21,243      $ 29,326   
  

 

 

   

 

 

 

See accompanying notes to these consolidated financial statements.

 

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RISE ENERGY OPERATING, LLC

CONSOLIDATED STATEMENTS OF OWNERS’ EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2012

(dollars in thousands)

 

     Non-controlling
Interest
     Owners     Total  
     (Unaudited)  

BALANCES, December 31, 2011

   $ 5,157       $ 68,795      $ 73,952   

Capital contributions

                      

Cash distributions

             (7,750     (7,750

Net income

     17         21,243        21,260   
  

 

 

    

 

 

   

 

 

 

BALANCES, September 30, 2012

   $ 5,174       $ 82,288      $ 87,462   
  

 

 

    

 

 

   

 

 

 

See accompanying notes to these consolidated financial statements.

 

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RISE ENERGY OPERATING, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011

(dollars in thousands)

 

     For the Nine Months
Ended September 30,
 
     2012     2011  
     (Unaudited)  

CASH FLOWS FROM OPERATING ACTIVITIES:

  

Net income

   $ 21,260      $ 29,097   

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depletion and depreciation

     5,278        6,024   

Accretion of discount on asset retirement obligations

     1,837        1,776   

Amortization of bond premium

     170        484   

Amortization of debt issuance costs

     118        230   

Unrealized loss on commodity derivatives

     (1,953     (9,102

Changes in operating assets and liabilities:

    

Accounts receivable

     (214     (3,079

Prepaid expenses and other current assets

     1,113        (1,412

Accounts payable

     (2,539     5,399   

Other assets and liabilities

     290        2,601   
  

 

 

   

 

 

 

Net cash provided by operating activities

     25,360        32,018   
  

 

 

   

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

    

Additions to oil and natural gas properties

     (10,740     (9,717

Additions to furniture, fixtures and equipment

     (185     (180

Additions to restricted investments

     (3,651     (4,256
  

 

 

   

 

 

 

Net cash used in investing activities

     (14,576     (14,153
  

 

 

   

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

    

Contribution from owners

            5,010   

Distributions to owners

     (7,750     (24,996

Proceeds from issuance of debt

     7,000          

Repayment of debt

     (12,000       
  

 

 

   

 

 

 

Net cash used in financing activities

     (12,750     (19,986
  

 

 

   

 

 

 

NET CHANGE IN CASH

     (1,966     (2,121

CASH, beginning of period

     8,066        11,534   
  

 

 

   

 

 

 

CASH, end of period

   $ 6,100      $ 9,413   
  

 

 

   

 

 

 

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:

    

Interest paid

   $ 819      $   
  

 

 

   

 

 

 

Taxes paid

   $ 124      $ 40   
  

 

 

   

 

 

 

Non-cash capital expenditures in liabilities

   $ 553      $   
  

 

 

   

 

 

 

See accompanying notes to these consolidated financial statements.

 

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RISE ENERGY OPERATING, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization

Rise Energy Operating, LLC (“REO” or “Company”), a Delaware limited liability company, was formed on September 20, 2011. The Company conducts its operations through its wholly owned subsidiaries: Rise Energy Operating, Inc., a Delaware corporation formed on February 3, 2009, Rise Energy Minerals, LLC, a Delaware limited liability company formed on November 25, 2009, Rise Energy Beta, LLC, a Delaware limited liability company formed on November 25, 2009, and Beta Operating Company, LLC, a Delaware limited liability company formed on November 25, 2009. Rise Energy Beta, LLC holds a 51.75% interest in the common stock of San Pedro Bay Pipeline Company (“SPBPC”), a California corporation, acquired on December 30, 2009. Prior to the formation of REO, its current subsidiaries were all affiliates under Rise Energy Partners, LP, a Texas limited partnership (“REP”). On September 20, 2011, upon formation of REO, the aforementioned affiliates were reorganized as subsidiaries of REO. No change in carrying values of assets and liabilities occurred as part of the reorganization of interests under common control.

The Company was formed to acquire, develop and produce oil and natural gas properties. The Company’s oil and gas reserves are located offshore southern California in federal waters.

Note 2—Basis of Presentation and Significant Accounting Policies

(a) Basis of Presentation

The accompanying financial statements have been prepared under accounting principles generally accepted in the United States (“GAAP”). The financial statements include the consolidated results of Rise Energy Operating, LLC and its wholly owned subsidiaries. The ownership interest of the non-controlling shareholder in SPBPC is presented as non-controlling interest in the financial statements. All material intercompany balances and transactions have been eliminated.

(b) Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting period.

Significant estimates include, but are not limited to, oil and gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of assets acquired and liabilities assumed in business combinations and asset retirement obligations. Actual results could differ from the estimates.

(c) Cash and Cash Equivalents

All highly liquid investments with an original maturity of three months or less are considered to be cash equivalents.

 

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RISE ENERGY OPERATING, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

 

(d) Concentration of Credit Risk and Significant Customers

Financial instruments that potentially subject the Company to credit risk consist principally of cash balances, accounts receivable and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts, which may, at times, exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Derivative financial instruments are generally executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. The Company also has netting arrangements in place with counterparties to reduce credit exposure. The Company has not experienced any losses from such investments.

During the nine months ended September 30, 2012 and 2011, the Company sold 93% and 100% of its oil production to one customer. If the Company were to lose its customer, the loss could temporarily delay production and sale of oil; however, management believes that it could identify a substitute customer to purchase the impacted production volumes. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company’s customer base. Management determines amounts to be uncollectable when the Company has used all reasonable means of collection and settlement. Amounts outstanding longer than the contractual terms are considered past due. Management believes all amounts included in accounts receivable at September 30, 2012 and December 31, 2011 will be collected, and therefore, no allowance for uncollectible accounts has been recorded.

(e) Depreciation, Depletion and Amortization of Property and Equipment

The Company follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.

Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net revenues, discounted at 10% per annum, from proved oil, gas and NGL reserves plus the cost of properties not subject to amortization. Estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties.

Future net revenues are calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of the period. Prices and costs used to calculate future net revenues were those as of the end of the appropriate quarterly period. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts.

Any excess of the net book value, less related deferred income taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period. No impairment of the net capitalized costs due to the full-cost limitation was necessary during the nine months ended September 30, 2012 or 2011.

 

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RISE ENERGY OPERATING, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

 

Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.

(f) Asset Retirement Obligations

The Company accounts for asset retirement obligations under ASC Topic 410, Asset Retirement and Environmental Obligations. ASC 410 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Under ASC 410, the liability for an asset retirement obligation is recorded at the asset’s inception, discounted to its present value using a credit-adjusted risk free interest rate. Typically, a corresponding amount is capitalized as an asset to the full cost pool. The liability is accreted each period and the asset is depreciated using the unit-of-production method as described above. Revisions to the estimated retirement obligation will result in an adjustment to the related asset and liability. If the liability is settled at an amount that differs from the recorded amount, unless significant, the difference is recorded to the full cost pool.

(g) Inventory

Inventory consists of oil volumes maintained within pipelines and storage tanks. The inventory volumes are recorded at lower of cost or market value. No market adjustment was required during the nine months ended September 30, 2012 or 2011.

(h) Debt Issuance Costs

Debt issuance costs were incurred to obtain financing under the revolving credit facility (see Note 7). These costs are recorded on the balance sheet and amortized over the term of the debt using the straight-line method which approximates the effective yield method.

(i) Revenue Recognition

The Company follows the sales method of accounting for oil revenue whereby revenue is recognized based on actual volumes of oil sold to purchasers. The Company and other joint interest owners may sell more or less than their entitlement share of volumes produced. Differences between oil and natural gas volumes sold and volumes to which the Company is entitled create imbalances. No material imbalances existed as of September 30, 2012 and December 31. 2011.

(j) Derivative Instruments and Hedging Activities

The Company may enter into commodity derivative instruments to reduce its exposure to fluctuations in commodity prices related to its forecasted oil and natural gas production. The Company has elected not to designate any of its positions for hedge accounting for financial statement purposes. Accordingly, the Company records the net change in the fair value of the instruments, as well as payments and receipts on settled contracts, in other income or expense on the statement of operations. The unrealized gains or losses on open commodity derivative positions are recorded at fair value on the Company’s balance sheet as current or non-current assets or liabilities based on the anticipated timing of the related cash flows.

 

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RISE ENERGY OPERATING, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

 

(k) Income Taxes

Rise Energy Operating, LLC has elected partnership status for income tax purposes and therefore does not pay income taxes.

Rise Energy Operating, Inc. and SPBPC are corporations and are subject to federal taxes. The Company records deferred tax assets and liabilities for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates of deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change. There have been no material changes to the deferred tax asset and liability balances in the nine months ended September 30, 2012 and 2011.

(l) New Accounting Pronouncements

In May 2011, the FASB issued an accounting standard update that amended previous fair value measurement and disclosure guidance. These amendments generally involve clarifications on how to measure and disclose fair value amounts recognized in the financial statements. They also expand the disclosure requirements, particularly for Level 3 fair value measurements, to include a description of the valuation processes used and an analysis of the sensitivity of the fair value measurements to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any. The Company adopted this amendment on January 1, 2012. The amendment did not have a material impact on our financial position, results of operations, cash flows or notes to the financial statements.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Note 3—Fair Value Measurement of Financial Instruments

The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonable available without undue cost and effort. These two types of inputs are further divided into the following fair value input hierarchy:

Level 1—Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2—Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable

 

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RISE ENERGY OPERATING, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

 

levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange-traded derivatives, such as over-the-counter commodity price swaps, collars, put options and interest rate swaps. At September 30, 2012 and December 31, 2011, all of the Company’s derivative instruments were considered Level 2.

Level 3—Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity).

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The carrying values of cash and cash equivalents, accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements included in the accompanying consolidated balance sheets approximated fair value at September 30, 2012 and December 31, 2011. The fair value estimates are based upon observable market data and are classified within level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables.

Derivative Instruments—The fair market values of the derivative financial instruments reflected in the balance sheets were based on quotes obtained from the counterparties to the agreements. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The fair value input hierarchy to which an asset or liability measurement falls is determined based on the lowest-level input that is significant to the measurement in its entirety. The following table presents the Company’s assets and liabilities that are measured at fair value on a recurring basis at September 30, 2012 and December 31, 2011 for each of the fair value hierarchy levels (in thousands):

 

     Fair Value Measurement at September 30, 2012 Using  
     Quoted
Prices in
Active
Markets
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs

(Level 3)
     Fair Value at
September 30,
2012
 

Assets:

           

Commodity derivative collar contracts

   $       $ 1,538       $       $ 1,538   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

   $       $ 1,538       $       $ 1,538   
  

 

 

    

 

 

    

 

 

    

 

 

 

Liabilities:

           

Commodity derivative swaps contracts

   $       $ 352       $       $ 352   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total liabilities

   $       $ 352       $       $ 352   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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RISE ENERGY OPERATING, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

 

     Fair Value Measurement at December 31, 2011 Using  
     Quoted
Prices in
Active
Markets
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs

(Level 3)
     Fair Value at
December 31,
2011
 

Assets:

           

Commodity derivative collar contracts

   $       $ 1,713       $       $ 1,713   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

   $       $ 1,713       $       $ 1,713   
  

 

 

    

 

 

    

 

 

    

 

 

 

Liabilities:

           

Commodity derivative collar contracts

   $       $ 2,480       $       $ 2,480   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total liabilities

   $       $ 2,480       $       $ 2,480   
  

 

 

    

 

 

    

 

 

    

 

 

 

For additional information on the Company’s derivative instruments, see Note 4.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis:

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s balance sheets. The following methods and assumptions were used to estimate the fair values:

Asset Retirement Obligations (ARO’s)—The Company estimates the fair value of ARO’s based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. See Note 5 for a summary of changes in ARO’s.

Properties Acquired in Business Combinations—If sufficient market data is not available, the Company determines the fair values of proved and unproved properties acquired in transactions accounted for as business combinations by preparing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.

Note 4—Risk Management and Derivative Instruments

The Company utilizes derivative instruments to manage exposure to commodity price and achieve a more predictable cash flow in connection with its oil sales from production. These transactions limit exposure to declines in prices, but also limit the benefits the Company would realize if prices increase.

Inherent in the Company’s portfolio of oil derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk by entering into

 

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RISE ENERGY OPERATING, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

 

derivative instruments only with counterparties that are large financial institutions, which management believes present lower credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into master netting agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty.

(a) Commodity Derivatives

The Company uses a combination of crude oil costless collars and swaps to manage its exposure to oil price volatility. At September 30, 2012, the Company had the following open commodity positions.

 

Crude Oil Collars

Beginning Month

 

Ending Month

 

Index

 

Average Monthly
Volumes (bbls)

 

Weighted

Average

Floor

 

Weighted

Average

Ceiling

10/1/2012

  12/31/2012   WTI   20,000   $70.00   $97.50

10/1/2012

  12/31/2012   WTI   10,000   $80.00   $101.50

10/1/2012

  12/31/2012   Brent   10,000   $90.00   $116.50

1/1/2013

  12/31/2013   WTI   10,000   $95.00   $116.65

1/1/2013

  12/31/2013   WTI   10,000   $95.00   $119.15

1/1/2013

  12/31/2013   Brent   10,000   $90.00   $108.75

1/1/2013

  12/31/2013   Brent   10,000   $100.00   $118.60

1/1/2014

  12/31/2014   Brent   10,000   $100.00   $107.40

1/1/2014

  12/31/2014   Brent   7,000   $90.00   $112.50

1/1/2015

  12/31/2015   Brent   25,000   $90.00   $104.50

 

Crude Oil Swaps

Beginning Month

 

Ending Month

 

Index

 

Average Monthly
Volumes (bbls)

 

Weighted Average
Fixed Price

1/1/2014

  6/30/2014   Brent   10,000   $98.20

7/1/2014

  12/31/2014   Brent   10,000   $99.10

(b) Balance Sheet Presentation

The following table summarizes the gross fair value of derivative instruments by appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at September 30, 2012 and December 31, 2011 (in thousands).

 

          September 30,     December 31,  

Type

  

Balance Sheet Location

   2012     2011  

Crude oil collars

   Current assets    $ 1,398      $ 397   

Crude oil collars

   Long-term assets      942        1,836   

Crude oil collars

   Current liabilities      (668     (2,877

Crude oil collars

   Long-term liabilities      (134     (123

Crude oil swaps

   Long-term liabilities      (352       
     

 

 

   

 

 

 

Net derivative financial instruments

   $ 1,186      $ (767
     

 

 

   

 

 

 

 

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RISE ENERGY OPERATING, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

 

(1) The fair value of the derivative instruments reported in the Company’s consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table reports the net derivative fair values as reported in the Company’s consolidated balance sheets at September 30, 2012 and December 31, 2011.

 

     September 30,     December 31,  
     2012     2011  
     (in thousands)  

Consolidated balance sheet classification:

    

Current derivative contracts:

    

Assets

   $ 1,398      $ 397   

Liabilities

     (668     (2,877
  

 

 

   

 

 

 

Net current

   $ 730      $ (2,480
  

 

 

   

 

 

 

Noncurrent derivative contracts:

    

Assets

   $ 942      $ 1,836   

Liabilities

     (486     (123
  

 

 

   

 

 

 

Net noncurrent

   $ 456      $ 1,713   
  

 

 

   

 

 

 

(c) Gains (Losses) on Derivatives

The Company does not designate instruments as hedging instruments for financial reporting purposes. Accordingly, all gains and losses, including unrealized gains and losses from changes in the derivative instruments’ fair values, have been recorded in the consolidated statements of operations. The following table details the unrealized and realized gains and losses related to derivative instruments for the nine months ended September 30, 2012 and 2011 (in thousands):

 

    

Statements of

Operations Location

   For the Nine Months
Ended
September 30,
 
          2012             2011      

Commodity derivative contracts

  

Unrealized gain on

commodity derivatives

   $ 1,953      $ 9,102   

Commodity derivative contracts

  

Realized loss on

commodity derivatives

     (661     (954

Note 5—Asset Retirement Obligations

The Company recognizes the fair value of its asset retirement obligations related to the plugging, abandonment, and remediation of oil and gas producing properties. The present value of the estimated asset retirement costs has been capitalized as part of the carrying amount of the related long-lived assets. The Company’s estimated asset retirement costs for the offshore oil and gas wells reflect the costs published by the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”), formerly known as Minerals Management Service.

 

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RISE ENERGY OPERATING, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

 

The liability has been accreted to its present value as of September 30, 2012. The following table represents a reconciliation of the Company’s asset retirement obligations for the period indicated (in thousands):

 

     For the Nine Months
Ended September 30,
2012
 

Asset retirement obligations at beginning of period

   $ 56,428   

Liabilities added from acquisitions or drilling

       

Current year accretion expense

     1,838   

Revision of estimates

       
  

 

 

 

Asset retirement obligations at end of period

   $ 58,266   
  

 

 

 

Note 6—Restricted Investments

The Company maintains various restricted investment accounts that fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds.

The components of the restricted investment balance at September 30, 2012 and December 31, 2011 are as follows:

 

     September 30,
2012
     December 31,
2011
 
     (in thousands)  

BOEMRE platform abandonment (See Note 9)

   $ 60,557       $ 57,348   

BOEMRE lease bonds

     776         776   

SPBPC Collateral*:

     

Contractual pipeline and surface facilities abandonment (See Note 9)

     1,867         1,595   

California State Lands Commission pipeline right-of-way bond

     3,000         3,000   

City of Long Beach pipeline facility permit

     500         500   

Federal pipeline right-of-way bond

     300         300   

Port of Long Beach pipeline license

     100         100   
  

 

 

    

 

 

 

Restricted investments

   $ 67,100       $ 63,619   
  

 

 

    

 

 

 

 

* These investments reside with SPBPC. Because SPBPC is fully consolidated, the amounts shown include the portion attributable to the non-controlling interest at September 30, 2012 and December 31, 2011.

Note 7—Long Term Debt

In March 2010, Rise Energy Beta, LLC and Rise Energy Minerals, LLC entered into a $50.0 million revolving line of credit with BNP Paribas. On December 31, 2010, the $50.0 million credit facility was amended to extend the maturity date to December 31, 2012, with quarterly principal payments beginning on March 31, 2012. On October 26, 2011, the Company refinanced this credit facility and entered into a $150.0 million revolving credit facility with BNP Paribas as Administrative Agent. On April 23, 2012, Wells Fargo replaced BNP Paribas as Administrative

 

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RISE ENERGY OPERATING, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

 

Agent. Amounts outstanding under the new credit facility are payable on October 26, 2014. At September 30, 2012 and December 31, 2011, $30.0 million and $35.0 million, respectively, were outstanding under the credit facility.

Amounts outstanding under the $150.0 million credit facility are limited to a borrowing base which is determined twice per year. In addition, the Company and Administrative Agent can request special borrowing base determinations, from time to time. The borrowing base was $50.0 million at September 30, 2012 and the borrowing base availability was $20.0 million at September 30, 2012 and $15.0 million at December 31, 2011.

Amounts outstanding under the credit facility elected as Eurodollar loans bear interest at the LIBOR rate plus a margin ranging from 2.25% to 3.25% payable at the end of the LIBOR loan period, not to exceed three months. Amounts outstanding subject to the Alternative Base Rate loan bear interest at a margin ranging from 1.25% to 2.25% plus the greater of the prime rate, federal funds effective rate plus a margin of 0.50%, or LIBOR rate plus a margin of 1%. Interest is payable quarterly. Amounts outstanding under the facility for the nine months ended September 30, 2012 were at a weighted average interest rate of approximately 3.07%. A commitment fee of 0.5% on the unused portion of the credit facility is payable quarterly in arrears.

The Company’s borrowings are secured by its assets and are subject to various financial and nonfinancial covenants. Significant financial covenants include maintaining: (1) a minimum current ratio, as defined, of 1.0 to 1.0, and (2) a maximum of debt to EBITDAX ratio for the previous four quarters, as defined, of 3.5 to 1.0. At September 30, 2012 and December 31, 2011, the Company was in compliance with its financial debt covenants.

Note 8—Related Party Transactions

The Company, as a subsidiary of REP, has agreed to perform, either itself or through its affiliates, administrative services for REP and REP has agreed to reimburse the Company for its expenses incurred in providing such services. These administrative services may include accounting, business development, finance, legal, information technology, insurance, government regulations, communications, regulatory, environmental and human resources services. Expenses are reimbursed based on the determination of management fees as deemed necessary. For the nine months ended September 30, 2012, no management fees were charged; however, for the nine months ended September 30, 2011, REP paid management fees to the Company in the amount $1.2 million, respectively. Management fees received from REP are presented as other revenue.

Note 9—Commitments and Contingencies

Litigation

The Company may from time to time be involved in various claims, lawsuits, disputes with third parties, or breach of contract incidental to the operations of its business. The Company is not currently involved in any litigation that it believes could have a materially adverse effect on its financial condition or results of operations.

Environmental

The Company is subject to extensive environmental laws and regulations. These laws, which are subject to change, regulate the discharge of materials into the environment and maintenance of

 

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RISE ENERGY OPERATING, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

 

surface conditions and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. As of September 30, 2012, the Company is not aware of any material environmental remediation obligations.

Sinking Fund Trust Agreement

In conjunction with the California working interest acquisition, the Company assumed an obligation with a third party to make payments into a sinking fund, the purpose of which is to provide funds adequate to decommission the portion of the San Pedro Bay pipeline that lies within State waters and the surface facilities. Under the terms of the agreement, the Company, as the operator of the properties, is obligated to make monthly deposits into the sinking fund account in an amount equal to $0.25 per barrel of oil and other liquid hydrocarbon produced from the acquired working interest. Interest earned in the account stays in the account. The obligation to fund ceases when the aggregate value of the account reaches $4.3 million. As of September 30, 2012, the gross account balance included in restricted investments was $1.9 million. The Company’s maximum remaining obligation net to its 51.75% interest under the terms of the current agreement was $1.3 million at September 30, 2012.

Supplemental Bond for Decommissioning Liabilities Trust Agreement

Also in conjunction with the California working interest acquisition, the Company assumed an obligation with the BOEMRE. Under the terms of the agreement dated March 1, 2007, the seller of the working interests was obligated to deliver a $90 million U.S. Treasury Note into a trust account for the decommissioning of the offshore production facilities. At the time of acquisition, all obligations under that agreement had been met.

In January 2010, the BOEMRE issued a report that revised upward, the estimated cost of decommissioning. In June 2010, the Company agreed to make additional quarterly payments to the trust account attributable to its net working interest of $0.647 million beginning on June 30, 2010 until the payments and accrued interest attributable to the Company equal $78.7 million by December 31, 2016. The trust account must maintain minimum balances attributable to the Company’s net working interest as follows (in thousands):

 

June 30, 2013

   $ 64,170   

June 30, 2014

     68,310   

June 30, 2015

     72,450   

June 30, 2016

     76,590   

December 31, 2016

     78,660   

In the event the account balance is less than the contractual amount, the working interest owners must make additional payments. As of September 30, 2012, the maximum remaining obligation net to the Company’s interest was approximately $17.8 million.

 

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RISE ENERGY OPERATING, LLC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

 

The trust account is held by the Company for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of September 30, 2012 (in thousands):

 

Investment

   Amortized
Cost
    Unrealized
Gain
(Loss)
    Fair
Market
Value
 

U.S. Bank Money Market Cash Equivalent

   $ 71,830      $      $ 71,830   

U.S. Government Treasury Note, maturity of March 31, 2013, and 2.50% coupon

     22,188        139        22,327   

U.S. Government Treasury Note, maturity of March 31, 2014, and 1.75% coupon

     23,000        597        23,597   

Less: Outside working interest owners share

     (56,461     (355     (56,816
  

 

 

   

 

 

   

 

 

 
   $ 60,557      $ 381      $ 60,938   
  

 

 

   

 

 

   

 

 

 

Office Lease

The Company leases administrative offices in Texas and California under non-cancelable operating leases. Commitments related to these lease payments are not recorded in the accompanying consolidated balance sheets. As of September 30, 2012, minimum future lease payments for all non-cancelable lease agreements were as follows (in thousands):

 

2012

   $ 76   

2013

     303   

2014

     244   

2015

     252   

2016

     149   
  

 

 

 

Total

   $ 1,024   
  

 

 

 

 

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Independent Auditors’ Report

The Board of Directors

Rise Energy Operating, LLC:

We have audited the accompanying Statement of Revenues and Direct Operating Expenses of Rise Energy Operating, LLC’s acquisition of certain offshore California platforms and the common stock of San Pedro Bay Pipeline Company (collectively, the Beta Unit), for the period January 1, 2009 through December 30, 2009. This financial statement is the responsibility of Rise Energy Operating, LLC’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement. We believe that our audit provide a reasonable basis for our opinion.

The accompanying financial statement was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and for inclusion in the registration statement on Form S-1 of Memorial Production Partners LP. The presentation is not intended to be a complete presentation of the Beta Unit’s revenues and expenses.

In our opinion, the financial statement referred to above presents fairly, in all material respects, the revenues and direct operating expenses described in note 1 of the Beta Unit’s financial statement for the period January 1, 2009 through December 30, 2009, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Dallas, Texas

November 19, 2012

 

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BETA UNIT

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE PERIOD JANUARY 1, 2009 TO DECEMBER 30, 2009

 

     Period Ended
December 30, 2009

(In thousands)
 

Operating revenues

   $ 54,971   

Direct operating expenses

     23,379   
  

 

 

 

Revenues in excess of direct operating expenses

   $ 31,592   

See accompanying notes to statement of revenues and direct operating expenses.

 

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BETA UNIT

NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE PERIOD JANUARY 1, 2009 TO DECEMBER 30, 2009

Note 1. Basis of Presentation

On November 6, 2009, Rise Energy Partners, LP, a Texas limited partnership (“REP”), acquired a 4.575% overriding royalty interest in producing offshore California oil wells from J. Aron & Company for a net purchase price of $16.2 million which REP subsequently contributed to a wholly-owned subsidiary. Simultaneous with acquiring the royalty interest, REP acquired from J. Aron & Company, 50.7% of the combined outstanding debt of Pacific Energy Resources Ltd. (“PERL”) for $68.8 million. On December 30, 2009, REP purchased certain assets from PERL through a competitive credit bid under Section 363 of the United States Bankruptcy Code. Under the terms of the credit bid and resulting Sale Order, REP and an unaffiliated company exchanged the then outstanding notes receivable from PERL and approximately $1,378,000 in cash, net to REP, for undivided interests in three offshore California platforms and the common stock of San Pedro Bay Pipeline Company (collectively, the “Beta Unit”). Concurrent with the consummation of the credit bid, REP contributed the resulting undivided 51.75% working interest in the Beta Unit to a wholly-owned subsidiary.

Historical financial statements prepared in accordance with accounting principles generally accepted in the United States of America had not previously been prepared for the Beta Unit. The accompanying statement of revenues and direct operating expenses related to the Beta Unit was prepared from the historical accounting records of PERL.

Certain indirect expenses, as further described in Note 4, were not allocated to the Beta Unit and have been excluded from the accompanying statement as such information is not readily available for the Beta Unit. Any attempt to allocate these expenses would require significant and judgmental allocations, which would be arbitrary and may not be indicative of the performance of the Beta Unit on a stand-alone basis.

The statement of revenues and direct operating expenses does not represent a complete set of financial statements reflecting financial position, results of operations, stakeholders’ equity and cash flows of the Beta Unit and are not necessarily indicative of the results of operations for the Beta Unit going forward. This statement of revenues and direct operating expenses represents 100% of the working interest in the Beta Unit of which REP acquired 51.75% and an unaffiliated company acquired 48.25% subsequent to the period presented herein.

Note 2. Significant Accounting Policies

Use of Estimates

Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the statement of revenues and direct operating expenses. Actual results could be different from those estimates.

Revenue Recognition

PERL used the sales method of accounting for oil revenues. Under the sales method, revenues are recognized based on actual volumes of oil sold to purchasers. There were no significant imbalances with other revenue interest owners during the period presented in this statement.

 

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BETA UNIT

NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE PERIOD JANUARY 1, 2009 TO DECEMBER 30, 2009

 

Direct Operating Expenses

Direct operating expenses relate to the direct expenses of operating the Beta Unit. The direct expenses include lease operating and facility operating expenses. Lease operating expenses include costs associated with maintaining the wells and the offshore platforms. Facility operating expenses include costs associated with maintaining the pipelines.

Note 3. Contingencies

The activities of the Beta Unit were subject to potential claims and litigation in the normal course of operations. Management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the Beta Unit.

Note 4. Excluded Expenses

This statement is not intended to be a complete presentation of the results of operations of the Beta Unit as it does not include general and administrative expenses, effects of derivative transactions, interest income or expense, depreciation, depletion and amortization, any provision for income tax expenses and other income and expense items not directly associated with operating revenues.

Note 5. Capital Expenditures (Unaudited)

Capital expenditures for the Beta Unit were $6.1 million for the period ended December 30, 2009.

Note 6. Supplemental Oil Reserve and Standardized Measure Information (Unaudited)

Estimated Quantities of Proved Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for the reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in financial statement disclosures.

Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will continue the project within a reasonable time.

 

 

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BETA UNIT

NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE PERIOD JANUARY 1, 2009 TO DECEMBER 30, 2009

 

The following table sets forth estimates of the proved oil reserves (net of the Bureau of Ocean Energy Management, Regulation and Enforcement royalty interest) for the Beta Unit and changes therein, for the period indicated. The oil price as of December 30, 2009 is based on the twelve month unweighted average of the first of the month prices of the West Texas Intermediate posted price which equates to $61.18 per barrel. Oil prices as of December 31, 2008, are based on the retrospective year end West Texas Intermediate posted price of $41.00 per barrel.

 

     Oil (Mbbls)  

Proved reserves at December 31, 2008

     2,541   

Revisions of estimates

     12,188   

Production (363 days)

     (1,027
  

 

 

 

Proved reserves at December 30, 2009

     13,702   

Proved developed reserves at December 30, 2009:

     5,617   

Standardized Measure of Discounted Future Net Cash Flows Relating to Oil and Gas Reserves

The following Standardized Measure of Discounted Future Net Cash Flow information has been developed utilizing ASC 932, Extractive Activities—Oil and Gas, (ASC932) procedures and based on oil reserve and production volumes estimated by the engineering staff for the Beta Unit. It can be used for some comparisons, but should not be the only method used to evaluate the Beta Unit or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted future Net Cash Flow be viewed as representative of the current value of the Beta Unit.

The following factors should be taken into account when reviewing the following information:

 

  Ÿ  

Future costs and selling prices will probably differ from those required to be used in these calculations;

 

  Ÿ  

Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; and

 

  Ÿ  

A 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural revenues

 

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BETA UNIT

NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE PERIOD JANUARY 1, 2009 TO DECEMBER 30, 2009

 

Under the Standardized Measure, for the year ended December 31, 2009, the future cash inflows were estimated by applying unweighted twelve month average of the first day of the month cash price quotes to the estimated future production of period end proved reserves. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. Use of a 10% discount rate and the unweighted twelve month average price were required. The Beta Unit is an unincorporated entity, and as such, no income tax effects were included in determining the Standardized Measure.

 

As of December 30, 2009 (in thousands):

  

Future cash inflows

   $ 729,713   

Future production costs

     (291,551

Future development costs

     (155,505
  

 

 

 

Future net cash flows before taxes

     282,657   

Future income taxes

       
  

 

 

 

Future net cash flows after taxes

     282,657   

Annual discount at 10%

     (107,788
  

 

 

 

Standardized measure of discounted future cash flows

   $ 174,869   
  

 

 

 

The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil reserves for the period indicated.

Changes in Standardized Measure

 

Standard measure, beginning of year

   $   

Oil and natural gas sales, net of production costs

     (33,270

Net changes in prices and production costs

     29,949   

Extensions, discoveries, additions and improved recovery, less related costs

       

Net changes in future development costs

     (19,630

Revision of quantity estimates

     241,143   

Purchases of minerals in place

       

Sales of minerals in place

       

Accretion of discount

       

Net change in income taxes

       

Changes due to timing and other

     (43,323
  

 

 

 

Standardized measure, end of year 12/30/09

   $ 174,869   
  

 

 

 

 

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REPORT OF INDEPENDENT AUDITORS

The Members

BlueStone Natural Resources Holdings, LLC

We have audited the accompanying statements of revenues and direct operating expenses of the oil and gas properties acquired by BlueStone Natural Resources Holdings, LLC from BP America Production Company (the BP Properties), as described in Note 1, for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of BlueStone Natural Resources, LLC’s and BP America Production Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the basis of accounting used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

The accompanying financial statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission for inclusion in Memorial Production Partners LP’s Form S-1, and are not intended to be a complete financial presentation of the BP Properties’ revenues and expenses.

In our opinion, the financial statements referred to above presents fairly, in all material respects, the revenues and direct operating expenses, as described in Note 1, of the BP Properties for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

/s/    Ernst & Young LLP

Houston, Texas

June 17, 2011

 

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BLUESTONE NATURAL RESOURCES HOLDINGS, LLC’S ACQUISITION OF

CERTAIN BP AMERICA PRODUCTION COMPANY PROPERTIES

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

 

     Three Months
Ended

March 31,
     For Years Ended December 31,  
     2011      2010      2010      2009      2008  
     (Unaudited)                       
     (In thousands)  

Operating revenues

   $ 3,732       $ 6,482       $ 18,896       $ 18,972       $ 45,538   

Direct operating expenses

     1,572         2,280         7,003         6,535         9,016   

Revenues in excess of direct operating expenses

   $ 2,160       $ 4,202       $ 11,893       $ 12,437       $ 36,522   

 

 

See accompanying notes to the statements of revenues and direct operating expenses.

 

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BLUESTONE NATURAL RESOURCES HOLDINGS, LLC’S ACQUISITION OF

CERTAIN BP AMERICA PRODUCTION COMPANY PROPERTIES

NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

AND FOR THE THREE MONTHS ENDED MARCH 31, 2011 AND 2010 (UNAUDITED)

Note 1:    Basis of Presentation

On May 31, 2011, BlueStone Natural Resources Holdings, LLC (“BlueStone”) acquired certain oil and gas properties from BP America Production Company (“BP”) through an exchange of BlueStone’s Eagle Ford assets located in Texas plus a cash payment of $20.0 million in exchange for BP’s South Texas assets (“BP Properties”). The accompanying statements of revenues and direct operating expenses are related to the BP Properties.

Historical financial statements prepared in accordance with accounting principles generally accepted in the United States of America have never been prepared for the BP Properties. The accompanying statements of revenues and direct operating expenses related to the BP Properties were prepared from the historical accounting records of BP.

Certain indirect expenses, as further described in Note 4, were not allocated to the BP Properties and have been excluded from the accompanying statements. Any attempt to allocate these expenses would require significant and judgmental allocations, which would be arbitrary and may not be indicative of the performance of the properties on a stand-alone basis.

These statements of revenues and direct operating expenses do not represent a complete set of financial statements reflecting financial position, results of operations, stakeholders’ equity and cash flows of the BP Properties and are not necessarily indicative of the results of operations for the BP Properties going forward.

As of May 31, 2011, there are no preferential rights outstanding on the properties acquired by BlueStone.

Note 2:    Significant Account Policies

Use of Estimates

Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the statements of revenues and direct operating expenses. Actual results could be different from those estimates.

Revenue Recognition

BP uses the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. There were no significant imbalances with other revenue interest owners during any of the periods presented in these statements.

Direct Operating Expenses

Direct operating expenses, which are recognized on an accrual basis, relate to the direct expenses of operating the BP Properties. The direct expenses include lease operating, ad valorem tax and production tax expense. Lease operating expenses include lifting costs, well repair expenses, surface repair expenses, well workover costs and other field expenses. Lease operating

 

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BLUESTONE NATURAL RESOURCES HOLDINGS, LLC’S ACQUISITION OF

CERTAIN BP AMERICA PROCUDTION COMPANY PROPERTIES

NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

AND FOR THE THREE MONTHS ENDED MARCH 31, 2011 AND 2010 (UNAUDITED)

 

expenses also include expenses directly associated with support personnel, support services, equipment and facilities directly related to oil and natural gas production activities of the BP Properties.

Note 3:    Commitment and Contingencies

The activities of the BP Properties are subject to potential claims and litigation in the normal course of operations. Pursuant to the terms of the asset exchange agreement between BP and BlueStone, any claims, litigation or disputes pending as of the effective date (January 1, 2011) or any matters arising in connection with ownership of the properties prior to the effective date are retained by BP.

Note 4:    Excluded Expenses

The BP Properties were part of a much larger enterprise prior to the date of the sale by BP to BlueStone. Indirect general and administrative expenses, interest, income taxes, and other indirect expenses were not allocated to the BP Properties and have been excluded from the accompanying statements. In addition, any allocation of such indirect expenses may not be indicative of costs which would have been incurred by the BP Properties on a stand-alone basis.

Also, depreciation, depletion, and amortization have been excluded from the accompanying statements of revenues and direct operating expenses as such amounts would not be indicative of the depletion calculated on the BP Properties on a stand-alone basis.

Note 5:    Sales to Affiliates

Sales prices are based on current market prices at the time of sale. Total sales to affiliates were $12.5 million, $10.8 million, and $25.4 million for the years ended December 31, 2010, 2009, and 2008, respectively. Total sales to affiliates were $2.4 million and $4.2 million for the unaudited three months ended March 31, 2011 and 2010, respectively.

Note 6:    Capital Expenditures (unaudited)

Capital expenditures for the BP properties were $0.2 million, $0.9 million, and $5.4 million for the years ended December 31, 2010, 2009, and 2008, respectively. Capital expenditures for each of the three months periods ended March 31, 2011 and 2010 were less than $0.1 million.

Note 7:    Subsequent Events

Subsequent events have been evaluated for recognition and disclosure through June 17, 2011. As of this date, no subsequent events have occurred.

 

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Supplemental Oil and Gas Information (unaudited)

Historical data provided by BP and supplemented by qualified petroleum engineers on the staff of BlueStone was provided to Netherland, Sewell & Associates, Inc. (NSAI), independent, third-party petroleum engineers, to perform an independent evaluation of proved reserves for the year ending December 31, 2010. Reserves for the years ended December 31, 2009, 2008, and 2007 have been estimated by BlueStone petroleum engineers using the December 31, 2010 reserve study and adjusting it for actual production and changes in prices for the intervening periods.

All information set forth herein relating to proved reserves as of December 31, 2010, including estimated future net cash flows and present values, from that date, is taken or derived from reports and information furnished by BP. These estimates were based upon review of historical production data and other geological, economic, ownership and engineering data provided and related to the reserves. No reports on our reserves have been filed with any federal agency. In accordance with the SEC’s rules, our estimates of proved reserves and the future net revenues from which present values are derived beginning in 2009, are based on an unweighted 12-month average of the first-day-of-the-month price for the period, held constant throughout the life of the properties. The 2007 and 2008 prices are based on the prices being realized as of the last day of the year in accordance with the then SEC guidelines. Operating costs, development costs and certain production-related taxes were deducted in arriving at estimated future net revenues.

The following unaudited table sets forth proved natural gas and crude oil reserves, all within the United States, at December 31, 2010, 2009 and 2008, together with the changes therein.

 

     Natural Gas
(MMcf)
    Crude
Oil (MBbls)
    Total (MMcfe)  

Quantities of proved reserves:

      

Balance December 31, 2007

     63,953        89        64,487   

Revisions(1)

     (709     (1     (715

Extensions

     25               25   

Production

     (5,890     (8     (5,938
  

 

 

   

 

 

   

 

 

 

Balance December 31, 2008

     57,379        80        57,859   

Revisions(1)

     (3,124     (4     (3,148

Extensions

     533               533   

Production

     (5,405     (7     (5,447
  

 

 

   

 

 

   

 

 

 

Balance December 31, 2009

     49,383        69        49,797   

Revisions(1)

     2,089        5        2,119   

Production

     (4,787     (9     (4,841
  

 

 

   

 

 

   

 

 

 

Balance December 31, 2010

     46,685        65        47,075   
  

 

 

   

 

 

   

 

 

 

 

(1) Revisions include only the impact of changes in product prices.

 

     Natural Gas
(MMcf)
     Crude
Oil (MBbls)
     Total (MMcfe)  

Proved developed reserves:

        

December 31, 2007

     63,953         89         64,487   

December 31, 2008

     57,379         80         57,859   

December 31, 2009

     49,383         69         49,797   

December 31, 2010

     46,685         65         47,075   

 

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Standardized measure of discounted future net cash flows relating to proved reserves (dollars in thousands):

 

     2010     2009     2008  

Future cash inflows

   $ 201,777      $ 187,622      $ 317,502   

Future production and development costs

      

Production

     (85,159     (81,653     (115,267

Development

                     

Future income taxes

     (1,412     (1,313     (2,223
  

 

 

   

 

 

   

 

 

 

Future net cash flows

     115,206        104,656        200,012   

10% annual discount for estimated timing of cash flows

     (57,867     (51,252     (103,334
  

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

   $ 57,339      $ 53,404      $ 96,678   
  

 

 

   

 

 

   

 

 

 

Future cash inflows are computed by applying a 12-month average commodity price adjusted for location and quality differentials for 2010 and 2009, to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end. The 2008 prices were computed on the year end prices in accordance with the, then current, SEC guidance. The discounted future cash flow estimates do not include the effects of derivative instruments. Average price per commodity follows:

 

Petroleum Product

   2010      2009      2008  

Natural Gas per Mcf

   $ 4.22       $ 3.72       $ 5.48   

Crude Oil per Bbl

   $ 73.17       $ 56.28       $ 40.89   

The following reconciles the change in the standardized measure of discounted future net cash flows (dollars in thousands):

 

     2010     2009     2008  

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

   $ 53,404      $ 96,678      $ 134,649   

Changes from:

      

Sales of natural gas, crude oil and natural gas liquids produced, net of production costs

     (12,583     (11,439     (37,994

Extensions

       1,314        80   

Net changes in prices and production costs

     10,285        (40,132     (13,821

Revisions of previous quantity estimates

     2,610        (5,313     (1,508

Net change in taxes

     (35     379        320   

Accretion of discount

     5,402        9,767        13,596   

Change in timing and other

     (1,744     2,150        1,356   
  

 

 

   

 

 

   

 

 

 

Aggregate change in standardized measure of discounted future net cash flows

     3,935        (43,274     (37,971

Standardized measure of discounted future net cash flow, end of year

   $ 57,339      $ 53,404      $ 96,678   
  

 

 

   

 

 

   

 

 

 

 

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INDEPENDENT AUDITORS’ REPORT

To the Board of Directors of WildHorse Resources

Houston, Texas

We have audited the accompanying statements of operating revenues and direct operating expenses of the Carthage Assets (the “Properties”), as defined in the purchase and sale agreement dated February 24, 2011, between a third party and WHT Energy Partners, LLC, for the years ended December 31, 2010, 2009, and 2008. The statements of operating revenues and direct operating expenses are the responsibility of WildHorse Resources’ management. Our responsibility is to express an opinion on the statements of operating revenues and direct operating expenses based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements of operating revenues and direct operating expenses are free of material misstatement. An audit includes consideration of internal control over financial reporting as it relates to the statements of operating revenues and direct operating expenses as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Properties’ internal control over financial reporting as it relates to the statements of operating revenues and direct operating expenses. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the statements of operating revenues and direct operating expenses, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statements of operating revenues and direct operating expenses. We believe that our audits provide a reasonable basis for our opinion.

The accompanying statements of operating revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 1 to the statements of operating revenues and direct operating expenses, and are not intended to be a complete presentation of the Properties’ results of operations.

In our opinion, such statements of operating revenue and direct operating expenses present fairly, in all material respects, the operating revenues and direct operating expenses of the Properties for the years ended December 31, 2010, 2009, and 2008, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the statements of operating revenues and direct operating expenses, effective December 31, 2009, the Properties adopted the updated oil and gas reserve estimation and disclosure rules.

/s/    Deloitte & Touche LLP

Houston, Texas

June 30, 2011

 

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WHT ENERGY PARTNERS, LLC—CARTHAGE ASSETS

STATEMENTS OF OPERATING REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008,

AND THE UNAUDITED THREE MONTHS ENDED MARCH 31, 2011 AND 2010

 

     For Years Ended December 31,      Three Months Ended March 31,  
     2010      2009      2008      2011      2010  
                          (Unaudited)  

OPERATING REVENUES

   $ 64,738,373       $ 60,072,234       $ 156,960,848       $ 15,069,257       $ 19,237,719   

DIRECT OPERATING EXPENSES

     17,692,153         18,823,562         28,005,122         4,064,070         4,594,636   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

REVENUES IN EXCESS OF DIRECT OPERATING EXPENSES

   $ 47,046,220       $ 41,248,672       $ 128,955,726       $ 11,005,187       $ 14,643,083   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

See notes to statements of operating revenues and direct operating expenses.

 

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WHT ENERGY PARTNERS, LLC—CARTHAGE ASSETS

NOTES TO STATEMENTS OF OPERATING REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008,

AND THE UNAUDITED THREE MONTHS ENDED MARCH 31, 2011 AND 2010

1.    Basis of Presentation

On April 8, 2011, WHT Energy Partners, LLC (“WHT”), acquired from a third party, its Carthage Assets (the “Properties”) for an aggregate purchase price of approximately $315 million, subject to customary adjustments for changes in net working capital and other adjustments. WHT is 50% owned by each of WildHorse Resources, LLC (“WildHorse”) and Tanos Energy, LLC (“Tanos”); these two companies share a common principal member. The accompanying historical statements of operating revenues and direct operating expenses were derived from the third party sellers consolidated historical accounting records related to the properties. These statements are not intended to be a complete presentation of the results of operations of the Properties as they do not include general and administrative expenses, effects of derivative transactions, interest income or expense, depreciation, depletion, and amortization, any provision for income tax expenses and other income and expense items not directly associated with operating revenues from natural gas, natural gas liquids, and crude oil. Historical financial statements reflecting financial position, results of operations, and cash flows required by accounting principles generally accepted in the United States of America are not presented as such information is not readily available on an individual property basis. Accordingly, the accompanying statements are presented in lieu of the financial statements required under Rule 3-05 of Securities and Exchange Commission (“SEC”) Regulation S-X.

Concentration of Credit Risk—Arrangements for crude oil and condensate, natural gas liquids, and natural gas sales are evidenced by signed contracts with determinable market prices and revenues are recorded when production is delivered. A significant majority of the purchasers of these products have investment grade credit ratings and material credit losses have been rare.

Revenue Recognition—Revenues are recorded on the entitlement method based on the Properties’ percentage ownership of current production. The gas volumes sold may be more or less than the gas volumes the Properties’ are entitled to based on the Properties’ ownership interest. These differences result in a condition known in the industry as a gas imbalance. The Properties’ natural gas imbalances are not significant.

Recently Issued Accounting Pronouncements—In January 2010, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2010-03, Oil and Gas Reserve Estimations and Disclosures. This update aligns the current oil and gas reserve estimation and disclosure requirements of Accounting Standards Codification (“ASC”) 932 with the changes required by the SEC final rule, “Modernization of Oil and Gas Reporting,” as discussed below. ASU 2010-03 expands the disclosures required for equity method investments; revises the definition of oil- and gas-producing activities to include nontraditional resources in reserves, unless not intended to be upgraded into synthetic oil or gas; amends the definition of proved oil and gas reserves to require 12-month average pricing in estimating reserves; amends and adds definitions in the master glossary that is used in estimating proved oil and gas quantities; and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ended on or after December 31, 2009. The Properties’ adopted ASU 2010-03, effective December 31, 2009, with the issuance of these statements. See the unaudited supplemental oil and gas information in Note 3 for more details.

 

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WHT ENERGY PARTNERS, LLC—CARTHAGE ASSETS

NOTES TO STATEMENTS OF OPERATING REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008,

AND THE UNAUDITED THREE MONTHS ENDED MARCH 31, 2011 AND 2010

 

In December 2008, the SEC released a final rule, “Modernization of Oil and Gas Reporting,” which amends the oil and gas reporting requirements. The key revisions to the reporting requirements include: using a 12-month average price to determine reserves, including nontraditional resources in reserves if they are intended to be upgraded to synthetic oil and gas; ability to use reliable technologies to determine and estimate reserves; and permitting the optional disclosure of probable and possible reserves. In addition, the final rule includes the requirements to report the independence and qualifications of the reserve preparer or auditor, to file a report as an exhibit when a third party is relied upon to prepare reserve estimates or conduct reserve audits, and to disclose the development of any proved undeveloped reserves (“PUDs”), including the total quantity of PUDs at year-end, material changes to PUDs during the year, investments and progress toward the development of PUDs, and an explanation of the reasons why material concentrations of PUDs have remained undeveloped for five years or more after disclosure as PUDs. The accounting changes resulting from changes in definitions and pricing assumptions are treated as a change in accounting principle that is inseparable from a change in accounting estimate, which is to be applied prospectively. The final rule is effective for annual reports for fiscal years ended on or after December 31, 2009. The Properties’ adopted the provisions of the new rule effective December 31, 2009 with the issuance of these statements. See the unaudited supplemental oil and gas information in Note 3 for more details.

2.    Use of Estimates

The preparation of the statements of operating revenues and direct operating expenses in conformity with accounting principles generally accepted in the United States of America requires WildHorse Resources’ management to make estimates and assumptions that affect the reported amounts of operating revenues and direct operating expenses during the respective reporting periods. Actual results may differ from the estimates and assumptions used in the preparation of the statements of operating revenues and direct operating expenses.

3.    Supplemental Oil and Gas Information (unaudited)

Proved reserves as of December 31, 2010, were estimated by qualified petroleum engineers at WildHorse and Tanos using historical data and other information from the records of the third party seller of the Properties. The reserves were independently audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent, third-party petroleum engineers. Reserves for the years ended December 31, 2009, 2008, and 2007, have been estimated by WildHorse and Tanos petroleum engineers using the December 31, 2010, reserve study which was audited by NSAI and adjusting it for actual production and changes in prices for the intervening periods.

All information set forth herein relating to the proved reserves as of December 31, 2010, including the estimated future net cash flows and present values, from that date, is taken or derived from the records of the third party seller of the Properties. These estimates were based upon review of historical production data and other geological, economic, ownership, and engineering data provided and related to the reserves. No reports on these reserves have been filed with any federal agency. In accordance with the SEC’s guidelines, estimates of proved reserves and the future net revenues from which present values are derived, beginning in 2009, are based on an unweighted 12-month average of the first-day-of-the-month price for the period, held constant throughout the life of the properties. The 2008 and 2007 prices are based on the prices being

 

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WHT ENERGY PARTNERS, LLC—CARTHAGE ASSETS

NOTES TO STATEMENTS OF OPERATING REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008,

AND THE UNAUDITED THREE MONTHS ENDED MARCH 31, 2011 AND 2010

 

realized as of the last day of the year in accordance with the then SEC guidelines. Operating costs, development costs, and certain production-related taxes, which are based on current information and held constant, were deducted in arriving at estimated future net revenues.

The proved natural gas, crude oil, and natural gas liquids reserves, all within the United States, specifically the contiguous area of Panola and Rusk Counties, Texas and De Soto Parish, Louisiana; northwest Texas, and northwest Louisiana, respectively, as of December 31, 2010, 2009, and 2008, together with the changes therein are as follows:

 

     Natural Gas     Crude     Natural Gas
Liquids
    Total  
     (MMcf)     Oil (MBbls)     (MBbls)     (MMcfe)  

Quantities of proved reserves:

        

Balance December 31, 2007

     236,597        2,737        11,555        322,350   

Revisions(1)

     401        3        17        527   

Production

     (12,744     (157     (539     (16,923
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance December 31, 2008

     224,254        2,583        11,033        305,954   

Revisions(1)

     308        4        17        432   

Production

     (9,991     (123     (490     (13,671
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance December 31, 2009

     214,571        2,464        10,560        292,715   

Revisions(1)

     536        5        23        699   

Production

     (8,591     (126     (452     (12,055
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance December 31, 2010

     206,516        2,343        10,131        281,359   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Revisions include only the effect of changes in product prices.

 

     Natural Gas      Crude      Natural Gas
Liquids
     Total  
     (MMcf)      Oil (MBbls)      (MBbls)      (MMcfe)  

Proved developed reserves:

           

December 31, 2007

     177,886         2,298         8,660         243,636   

December 31, 2008

     165,376         2,143         8,131         227,014   

December 31, 2009

     155,541         2,022         7,651         213,573   

December 31, 2010

     147,312         1,899         7,212         201,984   

Proved undeveloped reserves:

           

December 31, 2007

     58,711         440         2,895         78,715   

December 31, 2008

     58,878         441         2,903         78,939   

December 31, 2009

     59,030         442         2,910         79,142   

December 31, 2010

     59,204         444         2,918         79,375   

 

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WHT ENERGY PARTNERS, LLC—CARTHAGE ASSETS

NOTES TO STATEMENTS OF OPERATING REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008,

AND THE UNAUDITED THREE MONTHS ENDED MARCH 31, 2011 AND 2010

 

Standardized measure of discounted future net cash flows relating to proved reserves (dollars in thousands):

 

     2010     2009     2008  

Future cash inflows

   $ 1,371,218      $ 1,197,357      $ 1,499,970   

Future production and development costs:

      

Production

     (412,564     (404,461     (439,549

Development

     (100,802     (100,802     (100,802

Future income taxes

     (9,598     (8,381     (10,500
  

 

 

   

 

 

   

 

 

 

Future net cash flows

     848,254        683,713        949,119   
  

 

 

   

 

 

   

 

 

 

10% annual discount for estimated timing of cash flows

     (546,176     (436,890     (617,120
  

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

   $ 302,078      $ 246,823      $ 331,999   
  

 

 

   

 

 

   

 

 

 

Future cash inflows are computed by applying a 12-month average commodity price adjusted for location and quality differentials for 2010 and 2009 to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end. The 2008 prices were computed on the year-end prices in accordance with the, then current, SEC guidance. The discounted future cash flow estimates do not include the effects of derivative instruments. Average sales price per commodity follows:

 

Petroleum Product

   2010      2009      2008  

Natural Gas per Mcf

   $ 4.12       $ 3.60       $ 5.37   

Crude Oil per Bbl

     74.43         56.12         39.47   

Natural gas liquids per Bbl

     34.18         25.94         18.45   

 

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WHT ENERGY PARTNERS, LLC—CARTHAGE ASSETS

NOTES TO STATEMENTS OF OPERATING REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008,

AND THE UNAUDITED THREE MONTHS ENDED MARCH 31, 2011 AND 2010

 

The following reconciles the change in the standardized measure of discounted future net cash flows (dollars in thousands):

 

     2010     2009     2008  

Standardized measure of discounted future net cash flow— beginning of year

   $ 246,823      $ 331,999      $ 577,374   
  

 

 

   

 

 

   

 

 

 

Changes from:

      

Sales of natural gas, crude oil, and natural gas liquids produced—net of production costs

     (47,046     (39,268     (127,080

Net changes in prices and production costs

     84,583        (87,090     (173,900

Revisions of previous quantity estimates

     758        358        596   

Net change in taxes

     (517     664        1,785   

Accretion or discount

     24,999        33,583        58,299   

Change in timing and other

     (7,522     6,577        (5,075
  

 

 

   

 

 

   

 

 

 

Aggregate change in standardized measure of discounted future net cash flows

     55,255        (85,176     (245,375
  

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flow—end of year

   $ 302,078      $ 246,823      $ 331,999   
  

 

 

   

 

 

   

 

 

 

4.    Subsequent Events

We are not aware of any events that have occurred subsequent to December 31, 2010, but before June 30, 2011, the date the financial statements were available to be issued, that require consideration as adjustments to or disclosures in the financial statements.

* * * * * *

 

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APPENDIX A

Glossary of Terms

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

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

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

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

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

Bbl/d: One Bbl per day.

Bcf: One billion cubic feet of natural gas.

Bcfe: One billion cubic feet of natural gas equivalent.

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

Boe/d: One Boe per day.

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

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

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

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

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

 

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

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

Economically Producible: The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For this determination, the value of the products that generate revenue are determined at the terminal point of oil and natural gas producing activities.

Estimated Ultimate Recovery: Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

Exploitation: A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Exploratory Well: A well drilled to find and produce oil and natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have working interest.

MBbl: One thousand Bbls.

MBbls/d: One thousand Bbls per day.

MBoe: One thousand Boe.

MBoe/d: One thousand Boe per day.

MBtu: One thousand Btu.

MBtu/d: One thousand Btu per day.

Mcf: One thousand cubic feet of natural gas.

Mcf/d: One Mcf per day.

MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

 

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Net Acres or Net Wells: Gross acres or wells, as the case may be, multiplied by our working interest ownership percentage working interest.

Net Production: Production that is owned by us less royalties and production due others.

Net Revenue Interest: A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.

NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate and natural gas liquids.

Operator: The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.

OPIS: Oil Price Information Service.

Play: A geographic area with hydrocarbon potential.

Probabilistic Estimate: The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrences.

Productive Well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.

Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved Reserve Additions: The sum of additions to proved reserves from extensions, discoveries, improved recovery, acquisitions and revisions of previous estimates.

Proved Reserves: Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, elevation and the potential exists for an associated natural gas cap, proved oil reserves

 

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may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price used is the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved Undeveloped Reserves: Proved oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Realized Price: The cash market price less all expected quality, transportation and demand adjustments.

Recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reliable Technology: Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserve Life: A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year-end by production volumes. In our calculation of reserve life, production volumes are based on annualized fourth quarter production and are adjusted, if necessary, to reflect property acquisitions and dispositions.

Reserves: Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas

 

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that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

Spot Price: The cash market price without reduction for expected quality, transportation and demand adjustments.

Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the SEC and the Financial Accounting Standards Board (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

Undeveloped Acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Wellbore: The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

Working interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

Workover: Operations on a producing well to restore or increase production.

WTI: West Texas Intermediate.

The terms “analogous reservoir,” “development project,” “development well,” “economically producible,” “estimated ultimate recovery,” “exploratory well,” “probabilistic estimate,” “proved developed reserves,” “proved reserves,” “proved undeveloped reserves,” “reliable technology,” “reserves,” and “resources” are defined by the SEC.

 

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APPENDIX B

Netherland, Sewell & Associates, Inc. Summary Reserve Report

(Memorial Production Partners LP)

 

LOGO

November 16, 2012

Mr. John A. Weinzierl

Memorial Production Partners LP

1301 McKinney Street, Suite 2100

Houston, Texas 77010

Dear Mr. Weinzierl:

In accordance with your request, we have audited the estimates prepared by Memorial Production Partners LP (Memorial PPL), as of September 30, 2012, of the proved reserves and future revenue to the combined interests of Memorial PPL and its subsidiaries (collectively referred to herein as “Memorial”) in certain oil and gas properties located in Louisiana and Texas. It is our understanding that the proved reserves estimates shown herein constitute all of the proved reserves owned by Memorial. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). The estimates of reserves and future revenue have been prepared in accordance with the definitions and regulations of the SEC and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. We completed our audit on or about the date of this letter. This report has been prepared for Memorial PPL’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

The following table sets forth Memorial PPL’s estimates of the net reserves and future net revenue, as of September 30, 2012, for the audited properties:

 

     Net Reserves      Future Net Revenue (M$)  

Category

   Oil
(MBBL)
     NGL
(MBBL)
     Gas
(MMCF)
     Total      Present Worth
at 10%
 

Proved Developed Producing

     2,170.6         7,370.9         205,608.2         498,295.8         277,366.2   

Proved Developed Non-Producing

     237.0         1,257.7         34,109.0         88,630.7         37,479.1   

Proved Undeveloped

     2,294.2         8,085.6         145,080.3         455,605.6         112,476.9   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved

     4,701.8         16,714.2         384,797.7         1,042,532.0         427,322.1   

Totals may not add because of rounding.

 

LOGO

 

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LOGO

The oil reserves shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

When compared on a lease-by-lease basis, some of the estimates of Memorial PPL are greater and some are less than the estimates of Netherland, Sewell & Associates, Inc. (NSAI). However, in our opinion the estimates of Memorial’s proved reserves and future revenue shown herein are, in the aggregate, reasonable and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards. We are satisfied with the methods and procedures used by Memorial PPL in preparing the September 30, 2012, estimates of reserves and future revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by Memorial PPL.

The estimates shown herein are for proved reserves. Memorial PPL’s estimates do not include probable or possible reserves that may exist for these properties, nor do they include any value for undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Prices used by Memorial PPL are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period October 2011 through September 2012. For oil and NGL volumes in Willow Springs Field, the average WTI-Cushing spot price of $94.97 per barrel is adjusted by lease for quality and transportation fees. For oil and NGL volumes in all other fields, the average West Texas Intermediate posted price of $91.48 per barrel is adjusted by lease for quality, transportation fees, and regional price differentials. For gas volumes, the average Henry Hub spot price of $2.826 per MMBTU is adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $93.75 per barrel of oil, $38.37 per barrel of NGL, and $2.766 per MCF of gas.

Operating costs used by Memorial PPL are based on historical operating expense records. For nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs for the operated properties are limited to direct lease- and field-level costs and Memorial PPL’s estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Capital costs used by Memorial PPL are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. For County Lake and South Henderson Fields, abandonment costs used are Memorial PPL’s estimates of the costs to abandon the wells, platforms, and production facilities, net of any salvage value. For all other fields, Memorial PPL’s estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties. Operating costs are held constant throughout the lives of the properties, and capital costs and abandonment costs are held constant to the date of expenditure.

 

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LOGO

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, estimates of Memorial PPL and NSAI are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.

It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of major properties making up 97 percent of the present worth for the total proved reserves. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by Memorial with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. Our audit did not include a review of Memorial’s overall reserves management processes and practices.

We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this audit, along with data provided by Memorial, are on file in our office. The technical persons responsible for conducting this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

 

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LOGO

 

Sincerely,

 

NETHERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-2699

By:   /s/ C.H. (Scott) Rees III
 

C.H. (Scott) Rees III, P.E.

Chairman and Chief Executive Officer

 

 

By:   /s/ Justin S. Hamilton     By:   /s/ David E. Nice     By:   /s/ Richard B. Talley, Jr.
 

Justin S. Hamilton

Texas P.E. 104999

Vice President

     

David E. Nice

Texas P.G. 346

Vice President

     

Richard B. Talley, Jr.

Louisiana P.E. 36998

Vice President

Date Signed:  November 16, 2012     Date Signed:  November 16, 2012     Date Signed:  November 16, 2012

JSH:JLO

 

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

 

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APPENDIX C

Netherland, Sewell & Associates, Inc. Summary Reserve Report

(Beta Properties)

 

LOGO

November 16, 2012

Mr. John A. Weinzierl

Memorial Production Partners LP

1301 McKinney Street, Suite 2100

Houston, Texas 77010

Dear Mr. Weinzierl:

In accordance with your request, we have estimated the proved reserves and future revenue, as of September 30, 2012, to the combined interests of Rise Energy Beta, LLC (Rise Beta) and Rise Energy Minerals, LLC (Rise Minerals) in certain oil properties located in Beta Field, federal waters offshore California. The Rise Beta interest is a working and revenue interest, and the Rise Minerals interest is an overriding royalty interest. The combined interest is referred to herein as “Rise Consolidated”. It is our understanding that Memorial Production Partners LP (Memorial Operating) is in the process of purchasing Rise Energy Operating, LLC (Rise). Rise Beta and Rise Minerals are subsidiaries of Rise. We completed our evaluation on or about the date of this letter. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Memorial Production Partners LP’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Rise Consolidated interest in these properties, as of September 30, 2012, to be:

 

     Oil Reserves      Future Net Revenue (M$)  

Category

   Gross
(MBBL)
     Net
(MBBL)
     Total      Present
Worth at
10%
 

Proved Developed Producing

     21,413.3         8,480.1         408,045.3         216,246.7   

Proved Developed Non-Producing

     3,754.5         1,486.9         133,039.3         48,403.7   

Proved Undeveloped

     11,013.5         4,361.6         395,462.2         128,152.4   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved

     36,181.4         14,328.6         936,546.8         392,802.8   

Totals may not add because of rounding.

 

LOGO

 

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LOGO

 

The oil reserves shown include crude oil only. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Produced gas is flared or consumed in field operations.

The estimates shown in this report are for proved reserves. As requested, probable reserves that exist for these properties have not been included. No study was made to determine whether possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is the interest owner’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for the interest owner’s share of capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period October 2011 through September 2012. The average West Texas Intermediate posted price of $91.48 per barrel is adjusted by lease for quality, transportation fees, and a regional price differential. The adjusted oil price of $105.44 per barrel is held constant throughout the lives of the properties.

Operating costs used in this report are based on operating expense records of Rise. Operating costs for the Rise Beta interest properties include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Headquarters general and administrative overhead expenses of Rise Beta are included to the extent that they are covered under joint operating agreements for the operated properties. For the Rise Minerals interest properties, because no working interest is owned, no operating costs would be incurred; however, operating costs have been used in the determination of the economic limits. It is our understanding that Rise and its partners have paid for insurance coverage that exceeds those amounts required by various regulatory authorities. The discretionary insurance gross (100 percent) costs are approximately $280,000 per month. Since Rise and its partners expect to drop this discretionary coverage in January 2015, we have included that operating cost reduction on that date, as requested. Activities are also in progress to convert Beta Field electrical systems from on-site, diesel-generated power to purchased electricity beginning March 2015. This change is estimated to reduce gross (100 percent) monthly operating costs by $350,000. This reduction has been included in our operating cost estimates. All other operating costs are held constant throughout the lives of the properties.

Capital costs used in this report were provided by Rise and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Capital costs have been included for the Rise Minerals interest properties to determine whether workovers, new

 

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development wells, and production equipment requirements are economic. Capital costs are held constant to the date of expenditure.

It is our understanding that Rise and its partners estimate a gross (100 percent) cost of approximately $152,000,000 for decommissioning and abandonment of its three Beta Field platforms, wells, and associated equipment and pipelines. As of September 30, 2012, Rise and its partners have prefunded an escrow account of approximately $118,000,000 for the decommissioning and abandonment. A trust agreement requires Rise and its partners to fund this escrow account to $152,000,000. The additional gross investment of $34,000,000 is expected to sufficiently fund the account to cover the estimated decommissioning and abandonment costs and has been included in our estimates of future net revenue. Abandonment costs are held constant to the date of expenditure.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

 

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The data used in our estimates were obtained from Rise, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. The titles to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

 

Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
By:   /s/ C.H. (Scott) Rees III
  C.H. (Scott) Rees III, P.E.
  Chairman and Chief Executive Officer
By:   /s/ Joseph J. Spellman
  Joseph J. Spellman, P.E. 73709
  Senior Vice President

Date Signed: November 16, 2012

DMA:ABB

 

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

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

 

  (i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

 

  (ii) Same environment of deposition;

 

  (iii) Similar geological structure; and

 

  (iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

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

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 

  (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

 

  (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

 

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves—Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves—Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

 

  (i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

 

  (ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

 

  (iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

 

  (iv) Provide improved recovery systems.

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

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

 

  (i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.

 

  (ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

 

  (iii) Dry hole contributions and bottom hole contributions.

 

  (iv) Costs of drilling and equipping exploratory wells.

 

  (v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

 

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

 

(16) Oil and gas producing activities.

 

  (i) Oil and gas producing activities include:

 

  (A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

 

  (B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

 

  (C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

 

  (1) Lifting the oil and gas to the surface; and

 

  (2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

 

  (D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

 

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

 

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

 

(ii) Oil and gas producing activities do not include:

 

  (A) Transporting, refining, or marketing oil and gas;

 

  (B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

 

  (C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

 

  (D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

 

  (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

 

  (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

 

  (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

 

  (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

 

  (v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

 

  (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

 

  (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

 

  (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

 

  (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

 

  (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

 

(20) Production costs.

 

  (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

 

  (A) Costs of labor to operate the wells and related equipment and facilities.

 

  (B) Repairs and maintenance.

 

  (C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

 

  (D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

 

  (E) Severance taxes.

 

  (ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

 

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

  (i) The area of the reservoir considered as proved includes:

 

  (A) The area identified by drilling and limited by fluid contacts, if any, and

 

  (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

 

  (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

  (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

  (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

 

  (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

 

  (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

 

  (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

 

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:

 

  a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

 

  b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

 

  a. Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

 

  b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

 

  c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.

 

  d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

  e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
  f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

  (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

  (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

 

From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

 

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

 

  Ÿ  

The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

 

 

  Ÿ  

The company’s historical record at completing development of comparable long-term projects;

 

 

  Ÿ  

The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

 

 

  Ÿ  

The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

 

 

  Ÿ  

The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

 

 

  (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

 

(32) Unproved properties. Properties with no proved reserves.

 

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10,500,000 Common Units

Representing Limited Partner Interests

Memorial Production Partners LP

 

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PRELIMINARY PROSPECTUS

                    , 2012

 

 

RAYMOND JAMES

CITIGROUP

BofA MERRILL LYNCH

BARCLAYS

RBC CAPITAL MARKETS

WELLS FARGO SECURITIES

OPPENHEIMER & CO.

SANDERS MORRIS HARRIS

WUNDERLICH SECURITIES

 

 

 


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PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee and the FINRA filing fee, the amounts set forth below are estimates.

 

SEC registration fee

   $ 29,326   

FINRA filing fee

     32,750   

NASDAQ listing fee

     —     

Printing and engraving expenses

     150,000   

Accounting fees and expenses

     400,000   

Legal fees and expenses

     250,000   

Engineering expenses

     15,000   

Transfer agent and registrar fees

     7,000   

Miscellaneous

     115,924   
  

 

 

 

Total

   $ 1,000,000   
  

 

 

 

Item 14. Indemnification of Directors and Officers.

Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever. The section of the prospectus entitled “The Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference.

We and our general partner have entered into indemnification agreements with our directors which generally indemnify our directors to the fullest extent permitted by law. Our general partner maintains director and officer liability insurance for the benefit of its directors and officers.

Under the omnibus agreement, we have agreed to indemnify Memorial Resource for all claims, losses and expenses attributable to the post-closing operations of the properties contributed to us in connection with the closing of our initial public offering, to the extent that such losses are not subject to Memorial Resource’s indemnification obligations. Please read “Certain Relationships and Related Party Transactions—Related Party Agreements—Omnibus Agreement” for a discussion of Memorial Resource’s indemnification obligations.

Reference is also made to the underwriting agreement filed as an exhibit to this registration statement, which provides for the indemnification of us, our general partner, its officers and directors, and any person who controls us or our general partner, including indemnification for liabilities under the Securities Act.

 

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Item 15. Recent Sales of Unregistered Securities.

On April 27, 2011, in connection with the formation of Memorial Production Partners LP, we issued (i) the 0.1% general partner interest in us to our general partner for $1 and (ii) the 99.9% limited partner interest in us to Memorial Resource Development LLC for $999, in each case in an offering exempt from registration under Section 4(a)(2) of the Securities Act.

On December 14, 2011, in connection with our initial public offering, we issued 7,061,294 common units, 5,360,912 subordinated units, 21,444 general partner units and all of our incentive distribution rights to Memorial Resource and our general partner, as partial consideration for the properties contributed to us, in an offering exempt from registration under Section 4(a)(2) of the Securities Act.

There have been no other sales of unregistered securities within the past three years.

Item 16. Exhibits and Financial Statement Schedules.

(a) Exhibit Index

 

Exhibit
Number

   Description
1.1       Form of Underwriting Agreement
2.1#       Purchase and Sale Agreement, dated as of September 18, 2012, by and among Memorial Production Operating LLC, Goodrich Petroleum Company, L.L.C. and Goodrich Petroleum Corporation (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on September 19, 2012)
2.2#       Purchase and Sale Agreement, dated as of November 19, 2012, by and among Memorial Production Operating LLC and Rise Energy Partners, LP (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on November 20, 2012)
3.1       Certificate of Limited Partnership of Memorial Production Partners LP (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-1 (File No. 333-175090) filed on June 23, 2011)
3.2       First Amended and Restated Agreement of Limited Partnership of Memorial Production Partners LP (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)
3.3       Certificate of Formation of Memorial Production Partners GP LLC (incorporated by reference to Exhibit 3.4 to Registration Statement on Form S-1 (File No. 333-175090) filed on June 23, 2011)
3.4       Amended and Restated Limited Liability Company Agreement of Memorial Production Partners GP LLC (incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)
4.1       Specimen Unit Certificate representing common units (included in Exhibit 3.2 incorporated by reference herein)
4.2       Form of Restricted Unit Agreement under the Memorial Production Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 4.6 to Registration Statement on Form S-8 (File No. 333-178493) filed on December 14, 2011)
5.1       Opinion of Akin Gump Strauss Hauer & Feld LLP as to the legality of the securities being registered
8.1       Opinion of Akin Gump Strauss Hauer & Feld LLP relating to tax matters

 

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10.1       Omnibus Agreement, dated as of December 14, 2011, by and among Memorial Production Partners LP, Memorial Production Partners GP LLC and Memorial Resource Development LLC (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)
10.2       Tax Sharing Agreement, dated as of December 14, 2011, by and between Memorial Production Partners LP and Memorial Resource Development LLC (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)
10.3       Credit Agreement, dated as of December 14, 2011, among Memorial Production Operating LLC, as borrower, Memorial Production Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent for the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent for the lenders party thereto, BNP Paribas, Citibank, N.A. and Comerica Bank, as co-documentation agents for the lenders party thereto, and the other lenders party thereto (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K
(File No. 001-35364) filed on December 15, 2011)
10.4       Contribution, Conveyance and Assumption Agreement, dated as of December 14, 2011, by and among Memorial Resource Development LLC, BlueStone Natural Resource Holdings, LLC, BlueStone Natural Resources, LLC, Memorial Production Partners GP LLC, Memorial Production Partners LP and Memorial Production Operating LLC (incorporated by reference to Exhibit 10.4 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)
10.5       Purchase and Sale Agreement, dated as of December 14, 2011, by and among Memorial Resource Development LLC, Classic Hydrocarbons Holdings, L.P., Classic Hydrocarbons Operating, LLC, Craton Energy Holdings III, LP, Memorial Production Partners GP LLC, Memorial Production Partners LP and Memorial Production Operating LLC (incorporated by reference to Exhibit 10.5 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)
10.6       Contribution, Conveyance and Assumption Agreement, dated as of December 14, 2011, by and among Memorial Resource Development LLC, WHT Energy Partners LLC, Memorial Production Partners GP LLC, Memorial Production Partners LP and Memorial Production Operating LLC (Incorporated by reference to Exhibit 10.6 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)
10.7       Memorial Production Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.7 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)
10.8       First Amendment to Credit Agreement, dated as of April 30, 2012, among Memorial Production Operating LLC, as borrower, Memorial Production Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent for the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent for the lenders party thereto, BNP Paribas, Citibank, N.A. and Comerica Bank, as co-documentation agents for the lenders party thereto, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form
10-Q (File No. 001-35364) filed on May 15, 2012)
10.9       Second Amendment to Credit Agreement, dated as of September 18, 2012, by and among Memorial Production Partners LP, Memorial Production Operating LLC, Wells Fargo Bank, National Association, as administrative agent for the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent for the lenders party thereto, Citibank, N.A. and Comerica Bank, as co-documentation agents for the lenders party thereto, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on
September 19, 2012)
10.10       Third Amendment to Credit Agreement, dated as of December 3, 2012, by and among Memorial Production Partners LP, Memorial Production Operating LLC, Wells Fargo

 

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      Bank, National Association, as administrative agent for the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent for the lenders party thereto, Royal Bank of Canada, The Royal Bank of Scotland plc, Union Bank, N.A. and Comerica Bank, as co-documentation agents for the lenders party thereto, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 4, 2012)
21.1*       List of Subsidiaries of Memorial Production Partners LP
23.1       Consent of Netherland, Sewell & Associates, Inc.
23.2       Consent of KPMG LLP
23.3       Consent of KPMG LLP
23.4       Consent of Ernst & Young LLP
23.5       Consent of Deloitte & Touche LLP
23.6       Consent of Akin Gump Strauss Hauer & Feld LLP (contained in Exhibit 5.1)
23.7       Consent of Akin Gump Strauss Hauer & Feld LLP (contained in Exhibit 8.1)
24.1*       Powers of Attorney
99.1       Report of Netherland, Sewell & Associates, Inc. Summary of September 30, 2012 Reserves (included as Appendix B to the prospectus)
99.2       Report of Netherland, Sewell & Associates, Inc. Summary of September 30, 2012 Reserves (included as Appendix C to the prospectus)
99.3*       Report of Netherland, Sewell & Associates, Inc. Summary of December 31, 2011 Reserves
99.4*       Report of Netherland, Sewell & Associates, Inc. Summary of December 31, 2010 Reserves
99.5*       Netherland, Sewell & Associates, Inc. Summary of December 31, 2010 Reserves
99.6*       Netherland, Sewell & Associates, Inc. Summary Reserve Report
99.7       Report of Netherland, Sewell & Associates, Inc. (incorporated by reference to Exhibit 99.1 to Annual Report on Form 10-K (File No. 001-35364) for the year ended December 31, 2011)
99.8       Report of Netherland, Sewell & Associates, Inc. (incorporated by reference to Exhibit 99.3 to Current Report on Form 8-K (File No. 001-35364) filed on November 20, 2012)

 

* Previously filed.
# Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.

Item 17. Undertakings.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is

 

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asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on December 5, 2012.

 

MEMORIAL PRODUCTION PARTNERS LP

By:

  Memorial Production Partners GP LLC, its general partner

By:

 

/s/ John A. Weinzierl

  John A. Weinzierl
  President, Chief Executive Officer, and Chairman

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on the dates presented.

 

Signature

  

Title

 

Date

/s/ John A. Weinzierl

  John A. Weinzierl

   President, Chief Executive Officer, and Chairman (Principal Executive Officer)   December 5, 2012

/s/ Andrew J. Cozby

  Andrew J. Cozby

   Vice President and Chief Financial Officer (Principal Financial Officer)   December 5, 2012

/s/ Patrick T. Nguyen

  Patrick T. Nguyen

   Chief Accounting Officer (Principal Accounting Officer)   December 5, 2012

*

  Jonathan M. Clarkson

   Director   December 5, 2012

*

  Scott A. Gieselman

   Director   December 5, 2012

*

  Kenneth A. Hersh

   Director   December 5, 2012

 

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*

  P. Michael Highum

   Director   December 5, 2012

*

  Tony R. Weber

   Director   December 5, 2012

*

  Robert A. Innamorati

   Director   December 5, 2012

 

*By:  

/s/ John A. Weinzierl

 
  John A. Weinzierl  
  Attorney-in-Fact  

 

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EXHIBIT INDEX

 

Exhibit
Number

   Description
1.1       Form of Underwriting Agreement
2.1#       Purchase and Sale Agreement, dated as of September 18, 2012, by and among Memorial Production Operating LLC, Goodrich Petroleum Company, L.L.C. and Goodrich Petroleum Corporation (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on September 19, 2012)
2.2#       Purchase and Sale Agreement, dated as of November 19, 2012, by and among Memorial Production Operating LLC and Rise Energy Partners, LP (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on November 20, 2012)
3.1       Certificate of Limited Partnership of Memorial Production Partners LP (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-1 (File No. 333-175090) filed on June 23, 2011)
3.2       First Amended and Restated Agreement of Limited Partnership of Memorial Production Partners LP (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)
3.3       Certificate of Formation of Memorial Production Partners GP LLC (incorporated by reference to Exhibit 3.4 to Registration Statement on Form S-1 (File No. 333-175090) filed on June 23, 2011)
3.4       Amended and Restated Limited Liability Company Agreement of Memorial Production Partners GP LLC (incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)
4.1       Specimen Unit Certificate representing common units (included in Exhibit 3.2 incorporated by reference herein)
4.2       Form of Restricted Unit Agreement under the Memorial Production Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 4.6 to Registration Statement on Form S-8 (File No. 333-178493) filed on December 14, 2011)
5.1       Opinion of Akin Gump Strauss Hauer & Feld LLP as to the legality of the securities being registered
8.1       Opinion of Akin Gump Strauss Hauer & Feld LLP relating to tax matters
10.1       Omnibus Agreement, dated as of December 14, 2011, by and among Memorial Production Partners LP, Memorial Production Partners GP LLC and Memorial Resource Development LLC (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)
10.2       Tax Sharing Agreement, dated as of December 14, 2011, by and between Memorial Production Partners LP and Memorial Resource Development LLC (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)
10.3       Credit Agreement, dated as of December 14, 2011, among Memorial Production Operating LLC, as borrower, Memorial Production Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent for the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent for the lenders party thereto, BNP Paribas, Citibank, N.A. and Comerica Bank, as co-documentation agents for the lenders party thereto, and the other lenders party thereto (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)


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10.4       Contribution, Conveyance and Assumption Agreement, dated as of December 14, 2011, by and among Memorial Resource Development LLC, BlueStone Natural Resource Holdings, LLC, BlueStone Natural Resources, LLC, Memorial Production Partners GP LLC, Memorial Production Partners LP and Memorial Production Operating LLC (incorporated by reference to Exhibit 10.4 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)
10.5       Purchase and Sale Agreement, dated as of December 14, 2011, by and among Memorial Resource Development LLC, Classic Hydrocarbons Holdings, L.P., Classic Hydrocarbons Operating, LLC, Craton Energy Holdings III, LP, Memorial Production Partners GP LLC, Memorial Production Partners LP and Memorial Production Operating LLC (incorporated by reference to Exhibit 10.5 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)
10.6       Contribution, Conveyance and Assumption Agreement, dated as of December 14, 2011, by and among Memorial Resource Development LLC, WHT Energy Partners LLC, Memorial Production Partners GP LLC, Memorial Production Partners LP and Memorial Production Operating LLC (Incorporated by reference to Exhibit 10.6 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)
10.7       Memorial Production Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.7 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011)
10.8       First Amendment to Credit Agreement, dated as of April 30, 2012, among Memorial Production Operating LLC, as borrower, Memorial Production Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent for the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent for the lenders party thereto, BNP Paribas, Citibank, N.A. and Comerica Bank, as co-documentation agents for the lenders party thereto, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form
10-Q (File No. 001-35364) filed on May 15, 2012)
10.9       Second Amendment to Credit Agreement, dated as of September 18, 2012, by and among Memorial Production Partners LP, Memorial Production Operating LLC, Wells Fargo Bank, National Association, as administrative agent for the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent for the lenders party thereto, Citibank, N.A. and Comerica Bank, as co-documentation agents for the lenders party thereto, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on September 19, 2012)
10.10       Third Amendment to Credit Agreement, dated as of December 3, 2012, by and among Memorial Production Partners LP, Memorial Production Operating LLC, Wells Fargo Bank, National Association, as administrative agent for the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent for the lenders party thereto, Royal Bank of Canada, The Royal Bank of Scotland plc, Union Bank, N.A. and Comerica Bank, as co-documentation agents for the lenders party thereto, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 4, 2012)
21.1*       List of Subsidiaries of Memorial Production Partners LP
23.1       Consent of Netherland, Sewell & Associates, Inc.
23.2       Consent of KPMG LLP
23.3       Consent of KPMG LLP
23.4       Consent of Ernst & Young LLP


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23.5       Consent of Deloitte & Touche LLP
23.6       Consent of Akin Gump Strauss Hauer & Feld LLP (contained in Exhibit 5.1)
23.7       Consent of Akin Gump Strauss Hauer & Feld LLP (contained in Exhibit 8.1)
24.1*       Powers of Attorney
99.1       Report of Netherland, Sewell & Associates, Inc. Summary of September 30, 2012 Reserves (included as Appendix B to the prospectus)
99.2       Report of Netherland, Sewell & Associates, Inc. Summary of September 30, 2012 Reserves (included as Appendix C to the prospectus)
99.3*       Report of Netherland, Sewell & Associates, Inc. Summary of December 31, 2011 Reserves
99.4*       Report of Netherland, Sewell & Associates, Inc. Summary of December 31, 2010 Reserves
99.5*       Netherland, Sewell & Associates, Inc. Summary of December 31, 2010 Reserves
99.6*       Netherland, Sewell & Associates, Inc. Summary Reserve Report
99.7       Report of Netherland, Sewell & Associates, Inc. (incorporated by reference to Exhibit 99.1 to Annual Report on Form 10-K (File No. 001-35364) for the year ended December 31, 2011)
99.8       Report of Netherland, Sewell & Associates, Inc. (incorporated by reference to Exhibit 99.3 to Current Report on Form 8-K (File No. 001-35364) filed on November 20, 2012)

 

* Previously filed.
# Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.